Carbon Capture and Storage [2 ed.] 012812041X, 9780128120415

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Carbon Capture and Storage

Carbon Capture and Storage Second Edition

Stephen A. Rackley

Preface to the second edition

Since the first edition of this book was published in 2010, there has been a dramatic growth in the breadth and depth of research and development work on topics directed towards carbon capture, storage, and utilization (CCSU) in order to address the ever more pressing challenge of climate change. This R&D work, progressed through the creative efforts of thousands of physicists, chemists, biologists, engineers, and others, in teams working in both academic and industrial environments, has revealed many new and exciting potential routes towards the goal of a low energy and environmentally sound technology for carbon capture that is sufficiently low cost to be deployable on a global scale. Bi-phasic and switchable solvents, flexible metal-organic frameworks, and artificial photosynthesis are among many topics that have seen 10- to 30-fold increases in the cumulative number of published research papers during this period. Alongside this exploration of new avenues, similar efforts have also been directed towards improving the performance of the more mature processes such as amine absorption where, for example, catalysis of both absorption and regeneration, and solutions to amine degradation have seen similar increases in the volume of publications. Unfortunately this impressive progress has not been mirrored at the demonstration and deployment end of the technology development lifecycle, and one of the more disheartening aspects of preparing this second edition has been the need to extensively excise the lists of projects that had been announced in 2010, and to include addenda to several pilot project descriptions to the effect that the planned scale-up was canceled for a variety of reasons that can be conveniently gathered under the root cause heading—“political dithering.” The net result of the faltering support for demonstration projects is of course that the eventual need for carbon capture and storage on a global scale, including carbon-negative options such as biomass energy with carbon capture and storage (BECCS), becomes ever more certain. It is clearly impossible to adequately cover this wealth of new R&D work in a single revised volume, and the aim, as in the first edition, has been to demonstrate the breadth of the various subjects covered with sufficient detail in selected areas to encourage further exploration by the reader. The proceedings of the biennial Greenhouse Gas Technology Conferences would be a good place to start such further enquiry, all papers being available online (Open Access) in the journal Energy Procedia. The book is presented in five parts, dealing in turn with fundamentals, capture, storage/utilization and monitoring, transportation, and information resources.

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Preface to the second edition

The three chapters of Part I establish some fundamentals. Chapter 1 describes the global carbon cycle and outlines the perturbing impact of anthropogenic carbon dioxide emissions on carbon fluxes and sinks. In Chapter 2 a brief initial overview of CCSU technologies is given, taking each of the main industrial sources of carbon emissions as the starting point. Since capture from power generation plants will be the major focus of early implementation, Chapter 3 provides a comprehensive introduction to fossil fueled power generation technologies. The emphasis here is on the current state of the art and on systems under development that are likely to be deployed during the next 50-years—the period in which we can expect CCSU technologies to mature. With these foundations established, Part II provides a more detailed description of carbon capture technologies. The first two chapters are written from an industry perspective, for the power industry (Chapter 4) and other industries (Chapter 5), and the next five chapters from a technology perspective, covering absorption, adsorption, membrane, low temperature and distillation, and mineral carbonation technologies. Part III then addresses CO2 storage and monitoring, and CO2 utilization. Chapters 11 to 16 provide a discussion, much expanded from the first edition, of the wide range of features, events, and processes (geological, geomechanical, hydrodynamic, geochemical, etc.) that influence geological storage. Chapter 17 draws these threads together and looks at saline aquifer storage from a project operator’s perspective, starting with the assessment of potential storage sites, through storage planning to operations and abandonment. Other geological storage options, such as CO2-enhanced oil recovery (EOR), are covered in Chapter 18, while Chapter 19 provides an overview of the technologies such as 4D seismic for monitoring geological storage operations. Examples and case studies from a range of storage projects are included to ground the discussion in practical experience. The potential for CO2 storage in the oceans and in terrestrial ecosystems is discussed in Chapters 20 and 21, and the concluding chapter in Part III describes the increasingly broad field of CO2 utilization, including the recent advances in artificial photosynthesis. The transportation of CO2 between capture and storage sites, either by pipeline infrastructure or by marine transport, is covered in Part IV. The book concludes in Part V with a compendium of information resources, including units and conversion factors, a list of CCSU related acronyms, and a glossary of some of the key technical terms encountered. Each chapter includes a selected list of references, many freely available online, that are chosen to provide a lead-in for further study. An effective strategy to track subsequent work in a particular area is to use the “Cited by . . .” link that appears in the scholarly search function of a popular search engine. The current revision has benefited from input from a number of readers, including educators using the book as a key text in CCSU related courses. Further comments, suggestions, or other feedback from readers will continue to be most welcome; please send them to [email protected].

Preface to the second edition

xv

While the focus of this book is on the technical aspects of CCSU, many other factors will play a pivotal role in determining the extent to which these technologies are eventually deployed—chief among them being costs. Apart from some general indications of estimated or target costs of some CCSU options, this book avoids any analysis of the cost of implementation of the various technologies discussed. The capital and operating costs and the economics of individual projects will be highly case-dependent, with exchange rate volatility further complicating any general analysis. Future reductions in the costs and energy requirements of these technologies can also be expected, pending the outcome of ongoing R&D efforts and the learning from early demonstration projects. It has been a pleasure to work with the team at Elsevier on the preparation of this second edition, and my thanks are due to Sarah Hughes, Cari Owen, Kattie Washington, Alex White, and Anusha Sambamoorthy. ________________ In 2010, when the first edition of this book was in press, carbon capture and storage appeared to be on the brink of a period of rapid development and deployment, with a steadily growing list of announced projects. The few major projects that have progressed since then have done so either because of the market value of CO2 for EOR or because project operators have been prepared to take a strategic leap of faith, recognized that CCS is critical to the future of their industries—often that of hydrocarbon extraction. In the coming years we can confidently anticipate more exciting technical progress, but more important will be progress on the policy-driven incentives that are essential to encourage and enable early deployment. Jose´ Marı´a Figueres Olsen, former president of Costa Rica and first chairman of the Carbon War Room, speaking during the 2010 Earth Day, observed that . . . “There is no Planet B.” Perhaps, following the promising commitments at COP21, we may at least be on the brink of a Plan A. Stephen A. Rackley August 2017

Preface to the first edition

The seed from which this book has grown was planted by the launch of the Virgin Earth Challenge by Sir Richard Branson and former US Vice President Al Gore on February 9, 2007. The aim of the Challenge is to encourage the development of commercially viable new technology, processes, and methods that can remove significant volumes of anthropogenic greenhouse gases from the atmosphere and contribute materially to the stability of the earth’s climate. With emissions from fossil fuel combustion running at 6.0 6.5Gt C per year (Gt C 5 109 metric tonnes of carbon), a material contribution to climate stability implies the potential for deployment on a scale of 1Gt C per year, roughly a thousand times larger than any currently operating project. While these volumes seem prodigious, anthropogenic emissions pale into insignificance beside the natural fluxes such as terrestrial photosynthesis, at B120Gt C per year, and oceanic uptake and release at B90Gt C per year. A diverse range of carbon capture and storage (CCS) technologies are currently at various stages of research, development, and demonstration. While a few of these technologies have reached the deployment stage, many still require significant further development work to improve technical capabilities and reduce costs. Although front-runners are already emerging, it is likely that the long-term potential of CCS will be achieved through the application of a broad portfolio of different technologies. These could range from the current favorite—solvent-based capture from coal-fired power plants with geological storage—to the decarbonation of fuels ahead of combustion, the manipulation of ecological factors such as microbial populations or ocean fertility to increase carbon inventories in soils and in the oceans, and many others. The aim of this book is to contribute in small part to the progress of this endeavor by providing a comprehensive, technical, but non-specialist overview of technologies at various stages of maturity that, it is hoped, will provide technical background for decision makers and encourage a coming generation of students and young engineers to tackle the 21st century’s most important technological challenge. Various chapters of the book have benefited from review by a number of scientists and other professionals who are engaged in the broad range of technologies described here. My special thanks are due to Dr. John Benemann (Benemann Associates), Dr. Somayeh Goodarzi (University of Calgary), Rob and Karin Lavoie (Calpetra Research & Consulting), Dr. Klaus Lorenz (Ohio State University), Dr. Antonie Oosterkamp (Research Foundation Polytec), Dr. Edward Peltzer (Monterey Bay Aquarium Research Institute), Prof. James Ritter (University of

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Preface to the first edition

South Carolina), Prof. Anja Schuster (Universita¨t Stuttgart), Dr. Takahisa Yokoyama (Central Research Institute of Electric Power Industry [CRIEPI]), and ˚ bo Akademi University). Their critical input, generously Prof. Ron Zevenhoven (A provided, is reflected in these pages; the responsibility for the remaining shortcomings, errors, and omissions remains with the author. It has been a pleasure to work with the team at Elsevier in bringing this book to fruition, and my thanks are due to Ken McCombs and Irene Hosey, who shepherded and supported it from concept to completion, and to the production team—notably Donald Whitehead of MPS Content Services and Anne McGee—ably led by Maria Alonso. A final word of thanks is due to Jimmy, Larry, and Sergey, without whose vision this project would have been a far greater challenge. ________________ In the two decades since the 1990 publication by the UN Intergovernmental Panel on Climate Change of its First Assessment Report, in the face of an increasing body of evidence and understanding, the Panel’s careful language of uncertainty has been progressively strengthened to the point where the Fourth Assessment Report was able to state with very high confidence that “the net effect of human activities since 1750 has been one of warming. Most of the observed increase in global average temperatures since the mid-20th century is very likely due to the observed increase in anthropogenic GHG concentrations” (IPCC AR4, 2007). Looking beyond AR5, due in 2014, with new evidence mounting daily that the climatic impact of our activities is at the upper end of the range of predictions, the task before us is to ensure that, at the end of our finite window of opportunity for change, we do not conclude. “This earth is ruined! We gotta get a new one.” (Fey, T. (2007). Greenzo, 30Rock, 2 (5)). Stephen A. Rackley August 2009

Introduction

1

The fossil fuel resources of our planet—estimated at between 4000 and 6000 gigatons of carbon (Gt-C)—are the product of biological and geologic processes that have occurred over hundreds of millions of years and continue today. The carbon sequestered in these resources over geological time was originally a constituent of the atmosphere of a younger earth—an atmosphere that contained B1500 parts per million (ppm) CO2 at the beginning of the Carboniferous age, 360 million years ago, when the evolution of earth’s first primitive forests began the slow process of biogeological sequestration. Since the dawn of the industrial age, c.1750, and particularly since the invention of the internal combustion engine, B8% of these resource volumes have been combusted and an estimated 400 Gt-C released back into the atmosphere in the form of CO2. In the same period a further B160 Gt-C has been released to the atmosphere from soil carbon pools as a result of changes in land use. The atmospheric, terrestrial, and oceanic carbon cycles have dispersed the greater part of these anthropogenic emissions, locking the CO2 away by dissolution in the oceans and in long-lived carbon pools in soils. During the period since 1750, the CO2 concentration in the atmosphere has increased from 280 to 370 ppm (annual average) in 2000, and B400 ppm in 2015, the highest level in the past 650,000 years and one that is not likely to have been exceeded in the past 20 million years, where “likely” reflects the Intergovernmental Panel on Climate Change (IPCC) judgment of a 66%
90% chance. This increase in atmospheric CO2 concentration ([CO2]) influences the balance of incoming and outgoing energy in the earth
atmosphere system, CO2 being the most significant anthropogenic greenhouse gas (GHG). In its Fourth Assessment Report (AR4), published in 2007, the IPCC concluded that global average surface temperatures had increased by 0.74 6 0.18 C over the 20th century (Figure 1.1), and that “most of the observed increase in global average temperatures since the mid-20th century is very likely (.90% probability) due to the observed increase in anthropogenic GHG concentrations.” With the publication of AR5 in 2014, the global average temperature rise was revised to 0.85 6 0.20 C (1880
2012), and the probability of an anthropogenic cause was reassessed as “extremely likely” (.95% probability). Although anthropogenic CO2 emissions are relatively small compared to the natural carbon fluxes—e.g., photosynthetic and plant 1 soil respiration fluxes, at B120 Gt-C/year, are some 15 times greater than current emissions from fossil fuel combustion—these anthropogenic releases have occurred on a timescale of hundreds rather than hundreds of millions of years. Anthropogenic change has also reduced the effectiveness of certain climate feedback mechanisms; e.g., in many cases changes in land-use and land-management practices have reduced the

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00001-5 © 2017 Elsevier Inc. All rights reserved.

Carbon Capture and Storage Deviation from 20th century average (ºC)

4

1.0 0.8 0.6 0.4 0.2 0.0 –0.2 –0.4 –0.6 1900

1920

1940

1960

1980

2000

2020

Figure 1.1 Variation of the earth’s surface temperature during the 20th century. Source: Data courtesy NASA Goddard Institute for Space Studies.

ability of soils to build soil carbon inventory in response to higher atmospheric CO2, while ocean acidification has reduced the capacity of the oceans to take up additional CO2 from the atmosphere. The energy consumption of modern economies continues to grow, with some scenarios predicting a doubling of global energy demand between 2010 and 2050. Fossil fuels currently satisfy 85% of global energy demand and fuel a similar proportion of global electricity generation, and their predominance in the global energy mix will continue well into the 21st century, perhaps much longer. In the absence of mitigation, the resulting emissions will lead to further increase in atmospheric [CO2], causing further warming and inducing many changes in global climate. Even if [CO2] is stabilized before 2100, the warming and other climate effects are expected to continue for centuries, due to the long timescales associated with climate processes. Climate predictions for a variety of stabilization scenarios suggest warming over a multi-century timescale in the range from less than 2 C to 9 C or more. Although many uncertainties remain, there is little room for serious doubt that measures to reduce CO2 emissions are urgently required to minimize long-term climate change. While research and development efforts into low- or zero-carbon alternatives to the use of fossil fuels continues, the urgent need to move toward stabilization of [CO2] means that measures such as the capture and storage of carbon that would otherwise be emitted can play an important role during the period of transition to low-carbon alternatives. Within the field of carbon capture and storage (CCS), a diverse range of technologies is currently under research and development and a growing number of demonstration projects have been started or are planned. A few technologies have already reached the deployment stage, where local conditions or project specifics have made them economically viable, but for most technologies further development work is required to improve technical capabilities and reduce costs. Although it is possible with some confidence to identify the technologies that are most likely

Introduction

5

to yield to these efforts, it is also likely that deployment of CCS on a scale sufficient to have a meaningful impact on global emissions (referred to below as “impact scale deployment”) will be achieved through the application of a broad portfolio of different technical solutions. The remainder of this chapter provides the context for this challenge. First, the inventories and fluxes that make up the global carbon cycle are discussed. While the current CCS frontrunners make a direct attack on anthropogenic emissions by capturing CO2 from large sources before emission, reduction of the atmospheric carbon inventory can be achieved by any approach that can limit fluxes contributing to or enhance fluxes reducing this inventory. An understanding of these inventories and fluxes is therefore an essential grounding. Finally, the process of technological innovation is described. The concepts and terminology introduced here will be used throughout the book to locate various technologies and projects within the life cycle of technology development from research to commercial deployment.

1.1

The carbon cycle

The carbon inventories in the atmosphere, biosphere, soils and rocks, and the oceans are linked by a complex set of natural and anthropogenic biogeochemical processes that are collectively known as the carbon cycle. Figure 1.2 illustrates the inventories (bold font, units of Gt-C) and fluxes (italic font, units of Gt-C/year) that make up this cycle.

Atmosphere 850

Land use change 120 1

123

Vegetation 600 Soils 2000

Fossil fuels 9 Fossil fuels 8000–10000

Rivers 1

93

Marine biota 3

40 50

Volcanism 0.1

90

100

Surface ocean 1000

10

Deep ocean 38000

90 Sediments

0.2

Marine sediments 6000

Figure 1.2 Inventories and fluxes in the carbon cycle (2015 estimates).

Lithosphere 50 106

6

Carbon Capture and Storage

1.1.1 Carbon inventories The main inventories relevant to the global carbon cycle are described in the following section.

Carbon inventory of the atmosphere The atmospheric carbon inventory consists almost entirely of carbon dioxide, with a [CO2] of some 400 ppm (2015) or 0.04% by volume. As noted above, this inventory has risen by over 40% since pre-industrial times as a net result of emissions from fossil fuel combustion and changes in land-use and land-management practices. The remaining atmospheric carbon inventory consists of methane (CH4) at B1.8 ppm, with traces of carbon monoxide (CO) and anthropogenic chlorofluorocarbons also present. Detailed measurements of [CO2] were started by Charles Keeling at the National Oceanic and Atmospheric Administration (NOAA) Mauna Loa Observatory, Hawaii, in September 1957, with an average value of 315 ppm recorded for the first full year of measurements. The curve of increasing [CO2] established since that time is known as the Keeling curve, and the data from the start of the Mauna Loa continuous high-precision record in March 1958 are shown in Figure 1.3. The “milestone” of the first measured monthly average above 400 ppm was reached in April 2014 (or April 2015 when corrected for the seasonal trend) and, with a full year of monthly average [CO2] . 400 ppm being recorded in 2016, it seems doubtful that monthly averages below this level will again be seen during this century. The cyclical overprint on the continuously rising trend is shown in Figure 1.4 for individual years from 2000 to 2008 and as an average over this period. The cycle is synchronized with the northern hemisphere seasons, where [CO2] is drawn down

[CO2] at Mauna Loa (ppm)

420 400 380 360 340 320 300 1950

1960

1970

1980

1990

2000

2010

2020

Figure 1.3 [CO2] at Mauna Loa Observatory. Source: Data courtesy NOAA, Earth System Research Laboratory, Global Monitoring Division (Scripps CO2 Program).

Introduction

7

[CO2] Monthly–Annual trend (ppm)

4 3 2 1 0 –1 –2 –3 –4 Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov Dec

Figure 1.4 Annual [CO2] cycle, 2000
15. Source: Data courtesy NOAA, Earth System Research Laboratory, Global Monitoring Division (Scripps CO2 Program).

B3.5 ppm below the annual average trend by photosynthetic production from May to September and rebounds by a similar amount as a result of biomass decomposition from October to April. The amplitude of this annual [CO2] cycle at Mauna Loa has increased from B5.7 ppm in the late 1950s to B6.5 ppm over the 5 years to 2015. This is believed to be a consequence of increased primary photosynthetic production in northern terrestrial ecosystems, as a result of increasing [CO2] and temperatures. The total inventory of carbon in the atmosphere with [CO2] at 400 ppm is B850 Gt-C (2.12 Gt-C/ppm [CO2]), with an annual increase in [CO2] of B2 ppm corresponding to a net inventory increase of B4 Gt-C/year.

Carbon inventory of the biosphere and soils The terrestrial carbon inventory is estimated to hold 2600 Gt-C, of which 600 Gt-C is present as living biomass and 2000 Gt-C as organic carbon in soils and sediments (to 2 m depth). This inventory has declined by roughly 10% since pre-industrial times, and predominantly since the mid-19th century, as a result of changes in landuse and land-management practices—deforestation, conversion of grasslands to agricultural use, and intensive agricultural practices being the main contributors. The soil carbon inventory can be further classified according to the carbon residence time within soils, as shown in Table 1.1. This ranges from plant and animal detritus, which will be decomposed and emitted through respiration with a typical timescale of 1
10 years, to inert carbon, which is inaccessible to biological processes and will remain in the soil until physically removed by water or airborne transport. These processes are discussed further in Chapter 21.

8

Carbon Capture and Storage

Table 1.1 Soil carbon inventory, components, and lifetimes Component

Lifetime (years)

Inventory (Gt-C)

Plant and animal detritus Modified soil carbon Inert carbon Total

,10 10
1000 .1000

B450 B1350 B200 2000

Table 1.2 Oceanic carbon inventory Component

Inventory (Gt-C)

Bicarbonate ion Carbonate ion Dissolved CO2 Dissolved organic carbon Marine biomass Total

B36,000 B1300 B740 ,700 ,10 B39,000

Carbon inventory of the oceans The oceanic carbon inventory amounts to B39,000 Gt-C, with more than 90% of this being present as bicarbonate ions ðHCO2 3 Þ, as shown in Table 1.2. In addition, some 2500 Gt-C is present in marine carbonate sediments, which are gradually transformed into sedimentary rock over geological time. Of the dissolved CO2 inventory in the oceans, B135 Gt-C (18%) is anthropogenic, with an estimated uptake rate of B2 Gt-C/year. Within the oceans, three key processes—the biological and solubility pumps and the thermohaline circulation—drive the distribution of carbon between organic and inorganic fractions, and its transport and eventual deposition in sediments. These processes are described in Chapter 20.

Carbon inventory of the lithosphere The earth’s crust, which represents the upper part of the lithosphere, is the final geological carbon sink and is estimated to hold 5 3 107 Gt-C in sedimentary rocks, B20% of which is in the form of organic carbon and the remainder as limestone. Fossil fuels—coal, oil, and gas—together account for between 8000 and 10000 Gt-C, or B0.05% of the total organic carbon present in sedimentary rocks.

1.1.2 Carbon fluxes These carbon inventories are subject to constant flux as a result of a web of interlinking natural processes. In addition, human activity has introduced new fluxes, and the effect of these has, in turn, modified some of the natural fluxes through

Introduction

9

various feedback mechanisms. To date, the net feedback has been negative, with the result that only B45% of anthropogenic CO2 emissions remain in the atmosphere.

Atmosphere 2 ocean fluxes The exchange of CO2 between the atmosphere and the oceans occurs due to the difference in CO2 partial pressure between the atmosphere and surface waters, with an estimated B90 Gt-C being exchanged annually. This flux is controlled by two key processes: the global ocean circulation system, which exchanges surface water and deepwater on a 500- to 1000-year timescale, and the geochemistry of surface waters, in particular the removal of carbonate ions by ionic reactions and precipitation (Carbonate buffering; see Glossary). An increase in dissolved CO2 reduces the carbonate ion concentration ð½CO22 3 Þ due to the ionic reaction that forms bicarbonate ions: CO2 1 H2 O2H2 CO3 2H1 1 HCO2 3

(1.1)

2 H1 1 CO22 3 2HCO3

(1.2)

and

22 The alkalinity of the ocean, measured as ½HCO2 3  1 2 3 ½CO3 , is preserved in this reaction since one carbonate ion is converted into two bicarbonate ions. However, the decline in ½CO22 3  means that the ion is less available to react with additional dissolved CO2, reducing further uptake and resulting in an increase in acidity as a result of reaction (1.1). The rise in atmospheric [CO2] shown in Figure 1.3 has resulted in an increased rate of uptake of CO2 by the oceans, reducing the atmospheric carbon inventory by an estimated B2 Gt-C/year, or roughly one-quarter of anthropogenic emissions, in the period from 1990 to 2015. This additional uptake has resulted in an increase in surface ocean acidity, as the carbonate buffer has been depleted in these waters. As noted above, this will limit the ability of the ocean to sustain a similar level of CO2 uptake in response to future increases in atmospheric [CO2]. The ocean provides a slow-acting buffer to stabilize atmospheric [CO2], and any atmospheric perturbation will be dissipated by absorption into the ocean over a timescale of centuries. This is illustrated in Figure 1.5, which shows a simple model of the uptake by the ocean of a 100-year “pulse” of emissions at 6 Gt-C/year into the atmosphere, starting at year zero. In this model the ocean has taken up 50% of the emitted CO2 after 150 years and almost 75% after 1000 years. From an initial level of 350 ppm, [CO2] peaks at 550 ppm at the end of the emission pulse and declines to B430 ppm over the final 100 years.

600

1.0

500

0.8

400

0.6

300

0.4

200

0.2

100 0

200

400

600

800

Fraction of emitted CO2 remaining in the atmosphere

Carbon Capture and Storage

[CO2] (ppm)

10

0.0 1000

Years from start of emission period

Figure 1.5 Simple model of oceanic uptake of atmospheric CO2 emissions.

0

1

2

3

4

5

6 Gt-C/year Fossil fuel CO2 emissions

+6.2 ± 0.3

Net ocean uptake

–2.0 ± 0.5

Implied terrestrial uptake

–2.2 ± 1.6

Emission from land use change +1.5 ± 1.0 Net atmospheric increase Key; Emission/uptake volume -

+3.5 ± 0.1

Uncertainty range -

Figure 1.6 Implied terrestrial biosphere uptake from 1980 to 2005 carbon budget.

Atmosphere 2 terrestrial biosphere and soil fluxes Terrestrial photosynthesis removes an estimated 123 Gt-C/year from the atmosphere as gross primary production, of which about 60 Gt-C/year is reemitted through plant (autotrophic) respiration while the remainder is retained as net primary production (NPP), resulting in biomass growth. Soil respiration, primarily from the microbial communities that feed on plant detritus and root exudates (heterotrophic respiration), returns a further B55 Gt-C/ year to the atmosphere. Under steady state, the balance is made up of emissions back to the atmosphere as a result of natural fires and dissolved organic carbon export by rainwater runoff into rivers. Over the 25-year period from 1980 to 2005, the net flux from the atmosphere to the terrestrial biosphere is estimated to have been 0.7 Gt-C/year, as shown in Figure 1.6. This figure is the net result of an estimated B1.5 Gt-C/year of emissions resulting from land-use changes, balanced by an implied uptake of B2.2 GtC/year into the terrestrial biosphere.

Introduction

11

This net uptake is attributed to a CO2 fertilization effect, which increases NPP with increasing [CO2], as a result of increased photosynthetic efficiency and improved water-use efficiency in arid areas.

Atmosphere 2 lithosphere fluxes A carbon flux of B0.5 Gt-C/year from the atmosphere occurs as a result of the carbonate
silicate cycle in which carbonic acid, formed by the dissolution of CO2 in rainwater, causes the weathering of exposed silicate rocks according to the reaction: CaSiO3 1 H2 CO3 2CaCO3 1 SiO2 1 H2 O

(1.3)

The dissolved minerals are transported by rivers into the sea, adding to the ocean carbon inventory and carbonate buffer. The carbonate
silicate cycle is eventually closed over geological time by the subduction of sedimentary rocks formed by the precipitation and sedimentation of the weathering products. Metamorphosis in subduction zones reforms the silicate minerals, while CO2 is released through volcanoes. This CO2 flux from volcanic venting is estimated to add on average less than 0.1 Gt-C/year to the atmospheric inventory. The climatic impact of volcanic activity can however be far more significant, and complex, than this relatively small CO2 flux would suggest. One of the clearest deviations from the [CO2] growth trend shown in Figure 1.3 occurred in the 2 years following the eruption in June 1991 of Mount Pinatubo, on the Philippine island of Luzon. Rather than an increase in [CO2], the trend shows a plateau in 1992/93, which is attributed to the impact on ocean and land carbon cycles of the release of some 100 Mt-SO2.

1.2

Mitigating growth of the atmospheric carbon inventory

1.2.1 Anthropogenic emission scenarios The future level of anthropogenic CO2 emissions, from fossil fuel combustion, industrial emissions, and land-use changes, will be dictated by a wide range of demographic, socioeconomic, political, environmental, and technological factors, including: G

G

G

G

G

G

Population growth Economic growth and the globalization of trade Energy intensity of industrial production Fossil-fuel mix within the total energy supply Technology development in primary energy production and energy efficiency Environmental pressures and resulting policy-driven initiatives and incentives

12

Carbon Capture and Storage

Predicting any one of these factors over a 100-year time period carries a wide range of uncertainty, and the problem of combining multiple uncertainties is best handled by the creation of a number of scenarios, based on storylines that depict how these factors could play out in future. The IPCC created a set of such scenarios in the Special Report on Emissions Scenarios (SRES), published in 2000, and Figure 1.7 illustrates the total CO2 emissions, both from fossil-fuel consumption and land-use changes, generated for three of these scenarios as well as the maximum and minimum of the scenario range. Although these scenarios do include technological developments such as advanced power-generation systems and decarbonization of transport fuels, the implementation of CCS is not considered. While the IPCC scenarios have been overtaken by actual data for the first decade of the scenario period, they still provide a broad indication of the magnitude of the challenge that CCS seeks to address. Figure 1.8 illustrates the estimated [CO2] resulting from the SRES scenarios depicted in Figure 1.7 for a range of climate models, and shows [CO2] Total CO2 emissions (Gt-C/year)

40 SRES maximum

35

A1 Minicam

30

SRES range

A1 AIM B1 AIM

SRES minimum

25

A2

20 15

A1

10 B1

5 0 2000

2020

2040

2060

2080

2100

Figure 1.7 IPCC CO2 emissions scenarios. Source: Data courtesy IPCC, SRES 2000.

[CO2] (ppm)

1000

RCP8.5

800

A2

600

A1

RCP6.0 RCP4.5

B1

RCP2.6

400 200 0 1960

1980

2000

2020

2040

2060

2080

2100

Figure 1.8 Estimated atmospheric [CO2] resulting from SRES and AR5 RCPs.

Introduction

13

potentially rising to between 470 and 570 ppm by 2050 and into the 540
860 ppm range by 2100. For the Fifth Assessment Report (AR5), the SRES scenarios were replaced by a set of four Reference Concentration Pathways (RCPs) denoted RCP2.6, RCP4.5, RCP6.0, and RCP8.5. The RCP labels (2.6, 4.5, etc.) reflect different levels of radiative forcing (measured in W/m2) resulting from future emissions scenarios. Radiative forcing is the net change in radiation flux at the top of atmosphere (downward minus upward flux) due to a change in a climate change driver such as [CO2]. RCP4.5 therefore reflects a scenario in which total radiative forcing from all climate change drivers amounts to 4.5 W/m2 in 2100 relative to 1750. The RCPs span a slightly wider range in [CO2] at 2100 compared to the quoted SRES scenarios, as indicated in Figure 1.8.

1.2.2 CO2 stabilization scenarios The models used to predict [CO2] for a given emissions scenario can also be run to establish the range of emissions scenarios that would result in stabilization of [CO2] at a specific level. Figure 1.9 shows the emissions scenario data from Figure 1.7 together with the estimated range of emissions profiles that would permit [CO2] stabilization at 450 and 550 ppm. The ranges of the two sets of scenarios are extremely broad and can give only a very rough indication of the emissions reductions required to achieve a specified [CO2] target. SRES B1, which is based on an environmentally conscious and resource-conservative storyline with technology development aimed at improving primary energy-conversion efficiency, is predicted to result in [CO2] stabilization at around 550 ppm for many of the models, while, under this emissions scenario, capture and storage of between 100 and 200 Gt-C (370
730 Gt-CO2) would be required by 2050 to stabilize [CO2] at 450 ppm. This reduction target would rise to between 200 and 300 Gt-C (730
1100 Gt-CO2) by 2050 for stabilization at 450 ppm under the higher-emissions A1B SRES.

60

A2

20

550 ppm stabilization region A1

40

15 10

20

B1

5

450 ppm stabilization region 0 2000

2020

2040

2060

Figure 1.9 SRES and [CO2] target emissions ranges.

2080

2100

C emissions (Gt-C/year)

CO2 emissions (Gt-CO2/year)

80

14

Carbon Capture and Storage

Temperature change relative to 1861–1880 (°C)

Since the recognition by the 2009 UNFCCC Conference of Parties in Copenhagen (COP15) that, to prevent dangerous changes in the climate system, the increase in global temperature should be kept below 2 C, the presentation of emissions scenarios has focused on predicted temperature rise rather than [CO2]. For the RCPs used in AR5, it is predicted that global surface temperature change at 2100, relative to the period 1850
1900, is likely to exceed 1.5 C for all scenarios except RCP2.6. It is likely to exceed 2 C for RCP6.0 and RCP8.5, and more likely than not to exceed 2 C for RCP4.5. Warming is also expected to continue beyond 2100 for all RCP scenarios except RCP2.6. Figure 1.10 shows the predictions of global surface temperature change versus cumulative CO2 emissions, as predicted by a range of climate models for the four RCP scenarios. The figure shows that, compared to the RCP8.5 “Business as usual” scenario, some 200 Gt-C of emissions must be avoided by 2050, and over 1000 Gt-C by 2100—through the full range of mitigation options—if the 2 C limit is not to be exceeded. The foregoing indicates the scale of the challenge addressed by CCS and other mitigation options. In subsequent chapters a variety of ongoing and planned projects will be described, employing a range of technologies at various stages of development—from laboratory bench scale, to pilot and demonstration scale and finally up to full commercial scale—with throughputs ranging from a few kt-CO2/year up to 1 or 2 Mt-CO2/year. To contribute materially to meeting the challenge outlined above—to capture and store just 20 Gt-C by 2050—the largest of these current projects would need to be scaled up by a factor of 5 and deployed 200 times in the next 10
20 years. The technology development process that will be followed in progressing towards this massive step change is outlined in the next section.

5 RPC8.5

RPC range

4

3

RPC6.0 RPC4.5

2 RPC2.6

1 Circles ( ) indicate 2100 Squares ( ) indicate 2050

Historical

0 0

500

1000

1500

2000

2500

Cumulative anthropogenic carbon emissions from 1870 (Gt-C)

Figure 1.10 Global temperature change versus cumulative carbon emissions. Source: After IPCC AR5 Physical Science Basis, Figure SPM 10.

Introduction

1.3

15

The process of technology innovation

The process of technology development generally goes by the acronym RDD&D— Research, Development, Demonstration, and Deployment, the four stages describing the route that most new technologies take in maturing from fundamental research to commercial application. Table 1.3 describes the characteristics of each of these stages. An example of specific RD&D tasks at the first three stages is shown in Table 1.4 for the development of a membrane reactor based on technologies that will be discussed in Chapter 8.

1.3.1 Technology readiness level classification The progress of a new technology toward commercial deployment is captured in the Technology Readiness Level (TRL) scale, initially developed by NASA to classify the status of key mission components. Table 1.5 shows a set of TRL definitions based on those adopted by the EU Commission, including some additional description to link these to CCS applications. The TRL scale provides a common reference to assess development status across the full range of emerging technologies and is a useful communication and risk management tool to support policy and funding decisions regarding technology development and transitions.

1.3.2 RDD&D timescale Figure 1.11 shows the overall RDD&D timeline for the development of oxyfuel combustion technology for a coal-fired power plant, as planned (c.2005) by Vattenfall AB and partners and described further in Chapter 4. The 20-year timescale required to bring such technologies to the stage of readiness for commercial deployment highlights the corporate vision and sustained environmental commitment required to undertake such a project, while the outcome—briefly summarized below—highlights some of the pitfalls that lie along the RDD&D pathway. The development of new technology is rarely as linear as that implied by this sequence of steps. In reality, backward loops frequently occur, particularly from development back to research as obstacles encountered at the applied research stage demand additional work to establish new fundamental insights. An example of this will be encountered in Chapter 10, where development efforts to improve the reaction rate of mineral carbonation reactions have spawned a number of lines of research aimed at understanding the impact of pre-treatment on crystal and surface structure effects. In the Vattenfall oxyfuel example, the 30 MW Schwarze Pumpe pilot plant was commissioned as planned in year 8 (2008), but the planned 300 MW demonstration project in Ja¨nschwalde, which would have captured up to 1.7 Mt-CO2/year, was canceled in 2011 with the

Table 1.3 Stages in the technology development process Stage Research

Description

Fundamental research and experimental proof of concept, led by academic or industrial research organizations. Relatively low-cost exploration of a wide range of potential options. Definition of a “road map” detailing further fundamental and applied research requirements. Broad-brush estimate of eventual deployment costs and commercial viability. Development Progress along the development road map; applied research focusing on process engineering and system integration; laboratory- and pilotscale demonstration of the process. Additional fundamental research may be spawned as further implementation issues are identified. Refined construction and operating cost estimates and indications of commercial viability. Demonstration Initial industrial-scale implementation, often funded by government and industry partnerships. May involve the integration of existing, proven technologies in a new application. Evaluation and improvement of the design, construction, and operating processes. Budget-level definition of construction and operating costs. Deployment Progressive commercial implementation, which, in the early stages, may be accelerated by economic incentives in the form of capital grants or premium prices.

Current CCS examples (2017) Photocatalytic CO2 reduction to produce fuels; phase change sorbents

Chemical looping combustion

Air-separation using ion transport membrane for oxyfuel combustion; geological storage in depleted gas fields

Amine-based post-combustion capture; CO2 pipeline transportation; geological storage with enhanced oil recovery

Table 1.4 RD&D tasks for membrane reactor technology development Stage

Example RD&D tasks

Research (bench-scale testing)

Basic membrane and module materials research, and mathematical modeling Validation of mathematical models in a bench-scale experimental setup Build economic evaluation model Development (pilot-scale Construct pilot testing setup (membranes, module, and housing) testing) Perform pilot-scale testing and technical evaluation Possible recycle to bench-scale testing to resolve design, fabrication, or performance issues Refine process simulations for field-scale reactor design and perform optimization and integration studies Perform preliminary economic and business assessment Demonstration Fabricate field-scale test reactor (membranes, modules, (field-scale testing) reactor, catalysts) Prepare field test site and install reactor Perform field testing and technical evaluation Possible recycle to bench- or pilot-scale testing to resolve design, fabrication, or performance issues Conduct system integration study for full-scale deployment Refine performance simulation to optimize process operating conditions Finalize economic and business assessment

Table 1.5 TRL definitions for CCS applications Technology readiness level

Description

TRL 1—Basic research Basic principles postulated but no experimental proof TRL 2—Technology formulation Technology concept and application formulated TRL 3—Applied research Analytical or experimental proof of concept (e.g., bench-scale pilot testing of key elements) TRL 4—Small-scale prototype Technology validated in the laboratory (e.g., continuous operation of a small-scale pilot plant (,50 kWth)) TRL 5—Large-scale prototype Technology validated in intended environment (e.g., 50 kW
1 MWth pilot operated at industrially relevant conditions) TRL 6—Prototype system Performance demonstrated in intended environment (e.g., continuous steady-state operation of MWth pilot scale at industrially relevant conditions) TRL 7—Demonstration system System prototype demonstration in operational environment at pre-commercial scale (e.g., industrial pilot at .10 MWth) TRL 8—First commercial System complete and qualified (e.g., commercial scale scale system demonstration of manufacture, construction, and operation) TRL 9—Full commercial Technology fully proven in operational environment and application commercially available for customers Source: After Abanades et al. (2015).

YEAR

1

2

3

4

5

Research and Development Test rigs Experimental programs Pilot-scale plant Pre-feasibility and feasibility studies Project planning and detailed engineering Construction and commissioning Start-up and pilot operation Back-up site for Demonstration project

Demonstration stage Pre-feasibility and feasibility studies Project planning and detailed engineering Construction and commissioning Demonstration plant start-up and operation

Deployment stage (notional timeline) Pre-feasibility and feasibility studies Project planning and detailed engineering Construction and commissioning Full-scale plant start-up and operation

Figure 1.11 Vattenfall AB oxyfuel technology RDD&D timeline.

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

Introduction

19

Table 1.6 Characteristics of the technology development process Factor

Research

Academic involvement High Industry involvement Variable Costs Low to moderate Diversity of options Very wide Government General or targeted involvement research funding

Development

Demonstration Deployment

Moderate Moderate Moderate Wide Focused technology development funding

Low Low High High Moderate to high High Narrow Very narrow Market Market incentives incentives

company citing a “lack of political will.” Corporate budget pressures subsequently led to the cancelation of all Vattenfall AB’s remaining CCS R&D work. A technology may span several stages at once, e.g., being proven in one application or industry but not yet in another, and the integration of various elements that may individually be considered proven technology will often require an additional demonstration stage. While fundamental research and development work is generally directly transferable, the demonstration stage may need to be repeated to address location- or industry-specific aspects. Typically, the costs involved increase as a technology advances through successive stages in the process and, as shown in the Vattenfall oxyfuel example, progress of any project to the next stage is controlled by the availability of and competition for funding. Technical and commercial viability and, in the early stages, the prospect of that viability are also key drivers of such funding decisions. Several other factors that characterize the process are shown in Table 1.6. Governmental organizations often apply incentives to kick-start the demonstration and deployment phases by encouraging initial projects that may be marginal from a commercial perspective—an example being the provision of funding support for CCS demonstration projects. Subsequent deployment commonly results in reduced capital and operating costs as operating improvements and economies of scale are realized. If there is a conclusion to be drawn from the following chapters it is that, given the many and varied technologies that are being developed to address the challenges of CCS and the global record of technical innovation and progress of the past century, pursuit of these technologies has a high likelihood of delivering solutions that can meet the challenge. However, success in this venture also requires a globally shared political will and sense of urgency to create the enabling conditions for the deployment of these technologies on a massive scale. Whether that consensus and urgency will develop at a pace equal to the challenge is perhaps a bigger uncertainty than whether the technologies can deliver.

20

1.4

Carbon Capture and Storage

References and resources

1.4.1 References Abanades, J.C., et al., 2015. Emerging CO2 capture systems. Int. J. Greenhouse Gas Control. 40, 126
166. IPCC, 2000. Special Report on Emission Scenarios. Cambridge University Press, Cambridge, UK. IPCC, 2007. Climate Change 2007: The Physical Science Basis. Cambridge University Press, Cambridge, UK. Solomon, S.D. et al. (Eds.), Available at www.ipcc.ch/report/ar4. IPCC, 2008. Climate Change 2007: Synthesis Report. Pachauri, R.K., Reisinger, A. (Eds.), IPCC, Geneva, Switzerland. IPCC, 2014a. Climate Change 2014: Synthesis Report. Pachauri, R.K., Meyer, L.A. (Eds.), IPCC, Geneva, Switzerland. Available at www.ipcc.ch/report/ar5. IPCC, 2014b. Climate Change Mitigation: Working Group III Report. Available at www. ipcc.ch/report/ar5/wg3. Stern, N., 2006. Stern Review: The Economics of Climate Change. Cambridge University Press, Cambridge, UK. Available at http://webarchive.nationalarchives.gov.uk/ 20100407172811/; http://www.hm-treasury.gov.uk/stern_review_report.htm US DOE NETL, 2014. 2014 Technology Readiness Assessment—Carbon Capture and Storage Technologies. Available at www.netl.doe.gov/research/coal/publications Wigley, T.M.L., Schimel, D.S. (Eds.), 2000. The Carbon Cycle. Cambridge University Press, Cambridge, UK.

1.4.2 Resources Carbon Capture Journal: www.carboncapturejournal.com European CCS Demonstration Project Network: ccsnetwork.eu/content/ccs-projects European Commission. Technology readiness levels (TRL). Available at ec.europa.eu/research/ participants/data/ref/h2020/wp/2014_2015/annexes/h2020-wp1415-annex-g-trl_en.pdf EU Strategic Energy Technology (SET) Information Service: https://setis.ec.europa.eu/ Global CCS Institute, project database: www.globalccsinstitute.com/projects/large-scale-ccsprojects Global Carbon Project, publishing the annual Global Carbon Budget: www.globalcarbonproject.org GRID-Arendal: United Nations Environment Programme (UNEP) Collaboration Center, including access to IPCC Assessment and Special Reports: www.grida.no/publications Intergovernmental Panel on Climate Change (including AR5 published in 2014): www.ipcc.ch NASA Goddard Institute for Space Studies (GISS): www.giss.nasa.gov North American Carbon Program (assessing the sources and sinks of CO2, CH4, and CO in North America and adjacent oceans): www.nacarbon.org PBL Netherlands Environmental Assessment Agency, Annual report (Trends in Global CO2 Emissions) and global CO2 emissions time series data: edgar.jrc.ec.europa.eu RealClimate (commentary on climate science): www.realclimate.org State of the Carbon Cycle Report (SOCCR): The North American Carbon Budget and Implications for the Global Carbon Cycle: http://cdiac.ornl.gov/SOCCR/ US Carbon Cycle Science Program: https://carboncyclescience.us/

Introduction

21

US Department of Commerce, National Oceanic and Atmospheric Administration (NOAA), Earth System Research Laboratory, Global Monitoring Division (latest trend in atmospheric CO2): www.esrl.noaa.gov/gmd/ccgg/trends; data available at http://ftp.cmdl. noaa.gov/ccg/co2/trends/ US Department of Energy (DOE); Carbon Dioxide Information Analysis Center: cdiac.ornl. gov; Information on carbon sequestration RD&D projects: http://energy.gov/fe/scienceinnovation/carbon-capture-and-storage-research; National Energy Technology Laboratory (NETL), CCS Newsletter: www.netl.doe.gov/ research/coal/carbon-storage/carbonstorage-newsletter. US National Academy of Sciences; Climate change portal: https://nas-sites.org/ americasclimatechoices.

Overview of carbon capture and storage

2

The following sections provide an initial overview of the opportunities and technologies for CO2 capture and storage, both currently available and under development, as an introduction to the more detailed discussion in subsequent chapters.

2.1

Carbon capture

There are three main approaches to CO2 capture (Figure 2.1): 1. As a pure or near-pure CO2 stream, either from an existing industrial process or by reengineering a process to generate such a stream (e.g., oxyfueling or chemical looping power-generation plant, pre-combustion fuel gasification) 2. Concentration of the discharge from an industrial process into a pure or near-pure CO2 stream (e.g., post-combustion separation from power plant or cement plant flue gases) 3. Direct air capture into a pure CO2 stream or into a chemically stable end product (e.g., mineralization of steel slag)

2.1.1 Capture from power generation IPCC analysis (IPCC, 2005) shows that large fossil-fueled power plants account for almost half of the total CO2 emissions from fossil fuel combustion. These large point sources—defined as emitting . 0.1 Mt-CO2/year and summarized in Table 2.1—will be an essential area of application if CSS is to have a material impact on future CO2 emissions. Between 85% and 90% of global electrical power is generated from fossil fuel- and biomass-powered steam-driven turbines, a process illustrated schematically in Figure 2.2. The thermal efficiency of this type of plant is limited to B46% 48% by the achievable temperature of the working fluid (steam). This in turn is limited by the availability and cost of suitable materials that are required to withstand the high temperatures and pressures. Current technology limits steam temperatures and pressures to B625 C and 250 bar, although technologies under development are expected to raise this to 700 C and 350 bar by 2025. Generation efficiency is significantly improved in a combined cycle power plant, which uses hot combustion gases to directly drive a gas turbine and subsequently to generate steam in a heat-recovery steam generator, which then drives a steam turbine. A thermal efficiency of 60% can be achieved in current combined cycle power plants, and this can be increased to .80% if low-temperature waste heat is Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00002-7 © 2017 Elsevier Inc. All rights reserved.

24

Carbon Capture and Storage

Process modification N2 Fuel Fuel, air, or raw Air material Raw materials pre-processing

CO2 Power plant or industrial process

Process outputs N2

Post-process capture Fuel Air Raw materials

CO2 separation

Power plant or industrial process

CO2

Process outputs N2

Direct capture Air

Direct capture

CO2

Figure 2.1 Main approaches to CO2 capture.

Table 2.1 CO2 emissions from fossil-fueled power plants: large point sources (IPCC data) Power plant fuel

Emissions from identified sources (Mt-CO2/year)

Coal 7984 Natural gas 1511 Oil 980

Number of large point sources

Average annual emissions per source (Mt-CO2)

2025 1728 1108

3.9 0.9 0.9

Steam turbine

Steam

Electric power

Air Heat exchange

Condenser Heat exchange

Fuel Mill

Feedwater treatment

Ash removal Particulate removal

Figure 2.2 Schematic fossil-fueled electric-generation plant.

SOx NOx removal

Feed water

Flue gas emission

Overview of carbon capture and storage

25

also recovered for residential or industrial heating in a combined heat and power (CHP) application. The typical characteristics of flue gas from fossil fuel combustion are summarized in Table 2.2. CO is not shown in the table but may also be present in the case of incomplete combustion as a result of a limited oxygen supply in the combustion chamber. The CO2 content ranges from 3% to 15%, the lower end of this range (3% 5%) being typical for gas-fired plants and the upper end (12% 15%) for coal-fired plants. Three alternative approaches to CO2 capture from power generation are at various stages of development and are illustrated schematically in Figure 2.3.

Table 2.2 Typical fossil fuel combustion flue gas characteristics Parameter

Typical range of values

Pressure Temperature CO2

At or slightly above atmospheric pressure 30 80 C or higher, depending on the degree of heat recovery Coal-fired, 14% Natural gas-fired, 4% Coal-fired, 5% Natural gas-fired, 15% B81% Coal-fired, 500 5000 ppm Natural gas-fired, ,1 ppm Coal-fired, 100 1000 ppm Natural gas-fired, 100 500 ppm Coal-fired, 1000 10,000 mg/m3 Natural gas-fired, 10 mg/m3

O2 N2 SOx NOx Particulates

Post-combustion capture Coal, gas, biomass Power and heat

Flue gases

Air

CO2 separation

CO2

Pre-combustion capture Coal, gas, biomass Air, O2, steam

Gasification and reforming

CO2 separation

CO2 H2 fuel

Power and heat

Oxyfuel and chemical looping combustion CO2

Coal, gas, biomass Power and heat O2

Figure 2.3 Approaches to CO2 capture from power generation plants.

26

Carbon Capture and Storage

Minimum separation work (kWh/t-CO2 captured)

CO2 capture from flue gas is known as post-combustion capture, and techniques have been developed and implemented in the natural gas processing industry that are directly applicable to existing power plants. These technologies, which include chemical and physical sorbents and membranes, as well as hybrid approaches such as combining membranes with solvent or cryogenic methods, are described further in Chapter 4 and Chapters 6 9. The two alternatives to post-combustion capture aim to modify the combustion process so that a pure or high-concentration CO2 stream is generated. In the first of these, combustion of the fuel using pure oxygen rather than air results in a nearpure CO2 combustion gas stream that may require only minimal further processing before being compressed for transportation and storage. Oxygen for combustion may be delivered either as a gas (oxyfueling) or as an oxide (chemical looping combustion); these options are discussed further in Chapter 4. In the second alternative (pre-combustion capture), the fuel is partially oxidized and reacted with steam to form a CO2 and H2 mixture containing 15% 60% CO2, from which the CO2 can be separated by a range of techniques similar to those used for post-combustion capture. The resulting hydrogen fuel stream could then be combusted conventionally in a boiler or gas turbine, or put to a variety of other fuel uses. Pre-combustion capture is discussed further in Chapter 4. The theoretical minimum energy required to separate CO2 from a flue gas or syngas stream depends primarily on the CO2 concentration in the gas stream, as illustrated in Figure 2.4. Separation from natural gas combustion flue gases has a higher theoretical minimum due to the low [CO2] noted above, while postcombustion capture has the highest energy requirements for different coal-fired options. 200 30% MEA (3.85 GJ/t-CO2 solvent reboiler duty) 150 Direct air capture 100 Phase change solvents (1.9 GJ/t-CO2) 50

Natural gas combustion

Coal gasification (syngas)

Coal Steel/ post-combustion cement

0 0

10

20

30 40 CO2 concentration (%)

Figure 2.4 Minimum work required for CO2 separation.

50

Overview of carbon capture and storage

27

The figure also shows the impact of technological progress in reducing this energy cost in the case of coal-fired post-combustion capture, from the benchmark amine capture process to the emerging phase change solvents.

2.1.2 Capture from other industrial processes As well as power generation, a number of other industrial processes contribute a significant fraction of the total CO2 emissions from large (. 0.1 Mt-CO2/year) stationary sources. The most significant of these are summarized in Table 2.3 (IPCC, 2005). Capture from cement and steel production is briefly introduced below and is further discussed, along with other industrial processes, in Chapter 5.

Cement production Total global CO2 emissions from cement production are roughly double the volume identified in Table 2.3 from large point sources. Emissions amounted to B2 Gt-CO2 in 2008 and global growth of cement production averages B2.5% per year. The main raw material for cement production is calcium carbonate (CaCO3), derived from crushed limestone, chalk, marl, or shells. Small amounts of clay, shale, blast furnace slag, or ash are added during the production process to provide controlled quantities of aluminum, iron, and silicon. Cement is produced by heating the raw materials to produce slaked lime (CaO) and other compounds in the chemical process of calcination. Large roller kilns, operating at 1450 1500 C, fire the input slurry to produce marble-sized cement clinker, which is then crushed to yield the final fine-powder product. The energy input to the kiln is provided by combustion of coal, oil, or natural gas and, when combined with the gas released from calcination, yields a flue gas with [CO2] of typically 14% 33%. Global average CO2 emissions from cement production are B0.8 t-CO2/t-cement and are split roughly 50:50 between emissions resulting from the calcination reaction and those resulting from fuel combustion for kiln firing and other process requirements.

Table 2.3 CO2 emissions from industrial processes: large point sources (IPCC data) Process

Emissions from identified sources (Mt-CO2/year)

Cement production 930 Integrated steel production 630 Oil refining 800

Number of large point sources

Average annual emissions per source (Mt-CO2)

1175 180 638

0.8 3.5 1.3

28

Carbon Capture and Storage

The capture of CO2 from cement production is thus similar to post-combustion capture applied to power generation, with the key difference being the higher [CO2] compared to normal power-generation applications. Alternatively, by drafting the burners in the kiln with oxygen rather than air (analogous to oxyfuel combustion in power generation), an off-gas stream can be produced that would be suitable for compression and storage after minimal further treatment. These options are described in Chapter 5. A potentially material CO2 storage opportunity also arises where cement finds its end use in the construction industry, since CO2 can be absorbed in significant quantities during the curing of precast concrete products, such as masonry blocks. This opportunity is discussed in Chapter 22.

Integrated steel mills CO2 emission from steel production typically amounts to B1.4 t-CO2/t-steel produced for integrated steel mills using basic oxygen steelmaking, reducing to roughly a quarter of this (B0.3 t-CO2/t-steel) in the case of a steel recycling plant. At the end of the basic oxygen steelmaking process, described in Chapter 5, blast furnace gases contain B30% CO2, and the concentration in the overall flue gas stream from an integrated steel mill is B15%. This is in the same range as for coal-fired power plant, and the capture options introduced above for power generation are equally applicable for steel production, namely: G

G

G

“Post-combustion” capture from the overall flue gas stream. Firing the blast furnace with oxygen rather than air to give a CO plus CO2 off-gas stream. Capturing CO2 in a pre-combustion step and using hydrogen to reduce iron oxide in the blast furnace rather than CO.

These options are further described in Chapter 5.

2.1.3 Other capture options Direct air capture At the opposite end of the [CO2] spectrum from capture at B30% from a cement plant, the possibility of capture directly from ambient air at B0.04% has also been investigated, using various chemical absorption approaches. Although at first glance it would seem that capture from a flue gas stream with a high [CO2] would require far less energy input than capture from the air, the theoretical difference is surprisingly little: just 15 kJ/mol (equivalent to B95 kWh/t-CO2). This is some 4% 6% of the overall energy requirement of current amine-based absorption processes for flue gas CO2 removal (1600 2400 kWh/t-CO2). A sodium hydroxide (NaOH)-based spray-tower system capable of capturing 15 tCO2/year/m2 of contactor area has been demonstrated at laboratory scale and is described in Chapter 6. Scale-up of such a system to capture 1 Mt-CO2/year would require an absorber wall B10 20 m tall and 3 6 km long. The use of amine

Overview of carbon capture and storage

29

solvents, most commonly found in flue gas capture applications (see also Chapter 6), has also been investigated for direct air capture. This has a potential energy advantage due to a lower solvent regeneration temperature when compared to NaOH. Unlike other capture systems, which will reduce future emissions and limit the resulting increase in atmospheric [CO2], direct air capture, as a carbon-negative technology, has the potential to accelerate the natural decline in atmospheric [CO2] from a future peak level.

2.2

Carbon storage

2.2.1 Geological storage Injection into oil-, gas-, and water-bearing geological formations is widely regarded as the front-running option for CO2 storage and is the only option that has so far been applied on a commercial scale. The readiness of this option for commercial deployment is due to the use of site characterization, injection, and monitoring technologies that have been developed and widely deployed in the oil and gas industry. Two main storage options are available: storage in formations containing nonpotable water (saline aquifers) or in oil and gas reservoirs. The use of oil or gas reservoirs, whether producing or depleted, has a potential economic advantage if injection can enhance hydrocarbon recovery, as well as a risk-management advantage since the occurrence of hydrocarbons already demonstrates the presence of a sealing cap rock that has remained competent on a geological timescale (albeit without the potential geochemical impact of CO2). For saline aquifer storage, this sealing capacity will need to be demonstrated by initial site characterization studies and will also be an objective of monitoring throughout the life of the storage project. Depending on the future energy supply mix, stabilization of [CO2] at around 450 ppm by 2100 would require storage of some 1000 1500 Gt-CO2 before 2100. While this represents an immense challenge in terms of the required scale of investment, both capital and manpower, it is a modest amount when compared to estimates of global storage capacity. Although carrying a wide range of uncertainty, such estimates suggest a global capacity of 1000 1200 Gt-CO2 in depleted oil and gas fields, including EOR applications, up to 20,000 Gt-CO2 in saline aquifers and potentially twice this amount for in situ mineral carbonation. Available capacity is therefore unlikely to be a limit on CCS implementation, although matching source and storage locations will also require investment in CO2 transportation infrastructure. CO2 injection into oil reservoirs is widely practiced as an enhanced oil recovery (EOR) technique, particularly in the Permian Basin oilfields in the United States, using CO2 primarily sourced from naturally occurring CO2 reservoirs. EOR has also been applied using anthropogenic CO2 on a 2 Mt-CO2/year scale at the EnCana-operated Weyburn field and Apache Canada-operated Midale field in Saskatchewan, and a number of projects on a similar scale are at various stages of

30

Carbon Capture and Storage

planning for start-up in the next few years. Injection into depleted gas reservoirs has also been demonstrated, e.g., in the Gaz de France K12-B field in the North Sea, although enhanced gas recovery (EGR) benefits remain unreported. While lacking the direct economic incentives derived from incremental hydrocarbon production, saline aquifer storage has the potential advantage of being more geographically accessible to capture sites; global storage potential in saline aquifers is estimated to be one to two orders of magnitude greater than in oil and gas reservoirs. Saline aquifer storage at the 1 Mt-CO2/year scale has been demonstrated and is continuing at the Statoil-operated Sleipner and Snohvit fields in the North Sea, driven by the need to avoid venting of CO2 removed from natural gas production. A number of projects are currently being planned worldwide storing volumes of up to 1.5 Mt-CO2/year, and with start-up around 2020. Links to the informative databases of CCS projects maintained by the Global CCS Institute and the US DOE NETL are listed in Resources section. Coupling CO2 injection with geothermal energy extraction in a CO2 plume geothermal (CPG) system is one option that has been proposed to generate revenues (other than carbon credits) from saline aquifer storage. This option and the technologies involved in site characterization, injection, and monitoring for geological storage are described in Chapter 18 and Chapter 19.

2.2.2 Ocean storage With a carbon inventory some 50 times greater than the atmosphere, the ocean could be considered a prime candidate for storage of captured CO2, and several options have been investigated. Since surface waters exchange CO2 with the atmosphere on a timescale of months to years, storage would have to be at depth in order to prevent rapid release back to the atmosphere. Long-term storage by direct dissolution into deep waters could be achieved by venting gaseous CO2 or supercritical fluid at sufficient depth to ensure dispersal of the rising buoyant plume before it reaches surface waters. Venting could be either from a fixed pipeline or from a riser trailed behind a moving ship (Figure 2.5). The possibility of releasing CO2 in the form of hydrate particles—where each CO2 molecule is

Sea level

Rising gaseous plume

Critical pressure depth 800 m 1000 m Rising supercritical fluid or sinking hydrate plume

2000 m Buoyancy depth 3000 m

3000 m

Supercritical fluid lake

4000 m

Figure 2.5 Options for CO2 storage in the oceans.

Overview of carbon capture and storage

31

surrounded by a cage of water molecules—has also been investigated. This has the advantage that negative buoyancy is achieved at shallower depth (,1500 m) and the gradual dissolution of the sinking hydrate particles enhances mixing. Alternatively, CO2 could be stored as a lake of supercritical fluid if injected below the depth at which it becomes negatively buoyant in seawater (B3000 m) and at a location where the seabed topology provides lateral containment. Pools of this type have been observed in the vicinity of deepwater hydrothermal vents as a result of the separation of CO2 from vented gases. Experimental and small-scale in situ trials have been conducted to investigate the behavior and local environmental impact of CO2 injected into the sea. However, attempts to conduct larger trials have met with severe environmental opposition and have not gone ahead. Although the ocean will be the ultimate sink for all CO2 released into the atmosphere, over a timescale of centuries, the acceptability of the ocean as a direct storage site for CO2—the perception of solving one environmental problem by creating another—will be a major hurdle for further RD&D progress in this area. These and other storage options which focus on enhancing natural carbon sequestration processes in the oceans (e.g., increasing photosynthetic production in nutrientdepleted surface waters, either by direct fertilization or by wave-assisted upwelling of nutrient-rich deepwaters) are discussed further in Chapter 20. Processes that mimic the natural weathering of carbonate and other alkaline rocks have also been proposed that would, in some cases, use the ocean as both a source of water and a storage site for reaction products. This could potentially have a beneficial effect on ocean chemistry, e.g., by replacing depleted carbonate ions, although dispersal over a wide area would be required to avoid adverse local environmental impact. These and other mineral carbonation storage options are discussed in Chapter 10.

2.2.3 Storage in terrestrial ecosystems Unlike geological or ocean storage, in which the captured carbon is injected directly into the storage site, storage in terrestrial ecosystems is less direct and relies for the most part on the identification and control of the biogeochemical processes and conditions that determine the fate of carbon in these ecosystems. From the point of “capture” in photosynthesis, carbon is partitioned into a range of organic products, some of which are rapidly consumed, with CO2 released back to the atmosphere through respiration, while others have progressively longer residence times in the biomass and soil carbon inventories. Net storage in terrestrial ecosystems requires an enhancement of the processes that move carbon into longerlived pools by controlling factors such as: G

G

G

G

G

Land use (e.g., preserving or reestablishing forests and wetlands) Land-management practices, particularly relating to soil disturbance Plant types and cropping systems: debris retention, water-use efficiency, and lignin production Microbial community make-up: balance of fungal versus bacterial populations Soil fertility and irrigation, including wetting drying cycles

32

Carbon Capture and Storage

Although the total terrestrial carbon inventory is only some four times the atmospheric inventory (roughly three times in soils and one in biomass), active control of these factors could nevertheless have a material and low-cost impact on carbon uptake. At the same time, anthropogenic carbon emissions are being partially offset by a natural increase in the atmosphere-to-terrestrial carbon flux that is occurring through enhanced photosynthetic production as a result of increasing [CO2] and related climate changes. Interventions to increase carbon storage in terrestrial ecosystems will also enhance this natural feedback mechanism. One more direct option for carbon storage in terrestrial ecosystems, somewhat analogous to the direct geological or ocean storage, is the production of biochar by the pyrolysis of biomass and its storage as a soil amendment. This also has the potential to contribute to improved agricultural productivity of the storage sites. Processes and approaches to CO2 storage in terrestrial ecosystems are described in Chapter 21.

2.2.4 Storage by mineral carbonation Mineral carbonation is a potential storage method that accelerates the geological process of rock weathering. It involves the formation of stable carbonates by the reaction of CO2 with naturally occurring oxides or silicates of magnesium, iron, and calcium. In particular, igneous silicate rocks are globally abundant and contain important silicate minerals such as olivine ((Fex, Mg12x)2SiO4), wollastonite (CaSiO3), and serpentine (Mg3Si2O5(OH)4) which are potential feedstocks for mineral carbonation. The carbonation reactions typically require B2 t-silicate mineral/t-CO2 captured, so application of mineral carbonation would entail very-large-scale mining and disposal operations. For example, a 100 kt/day mining operation would be able to support capture of B18 Mt-CO2/year and could serve about five 500 MWe coal-fired power stations. In addition, backfilling operations would need to accommodate an excess of 50 100 kt/day of carbonation products. Apart from this type of mining-based application, the alkaline waste from many industrial processes is also suitable as feedstock for mineral carbonation, providing the opportunity for smaller-scale application. Wastes such as ash from municipal waste incineration, coal combustion, and cement production, as well as slag from steelmaking and asbestos mine tailings, are potential feedstocks. Some of these wastes have a resale value into other industries, but the end products after mineral carbonation generally have a higher value, offering an economic incentive to plant owners. Mineral carbonation, may be the preferred sequestration option for smaller, more dispersed industrial sources or where there are barriers to CO2 transportation or availability of local geological storage sites, and is described in Chapter 10.

Overview of carbon capture and storage

33

2.2.5 Other storage and use options The use of CO2 as an industrial feedstock is dominated by the production of urea (NH2CONH2) as a nitrogen fertilizer, which currently consumes B90 Mt/year of industrially produced CO2. Other uses include the production of methanol (CH3OH), polyurethanes, and the food industry, and total industrial use is estimated at B120 Mt-CO2/year. Although this is a significant quantity against the scale of current capture and storage projects, the scope to increase this usage is limited by the demand for the end products. Also, the retention time of carbon in these products is mostly very short; e.g., it is less than a year for urea, which quickly hydrolyzes to ammonia and CO2 when applied. The relevance of these uses for material long-term storage is therefore very limited. Potential applications at an advanced stage of development that could have a material impact include the production of precipitated calcium carbonate (PCC) for use in the paper and cement industries, and the direct use of cooled flue gases as a CO2 source for microalgal photosynthesis, generating biomass for biofuel production. The latter application would be carbon-neutral if the biofuel is subsequently burned without capture, or would be carbon-negative if CO2 is also captured in the biofuel combustion process. Catalytic conversion of CO2 to fuels such as methane and methanol, including engineered or artificial photosynthesis, is another suite of options, mostly at the early fundamental research stage which could eventually have a global impact. These and other CO2 usage options are described in Chapter 22.

2.3

Life-cycle analysis of CCS technologies

While the various approaches to capturing and storing CO2 outlined above deliver direct environmental benefits in the form of reduced emissions at the capture site, this benefit is accompanied by an increase in the energy intensity of the underlying process, e.g., due to the energy required to regenerate solvents used in the capture process or for CO2 compression, etc. The construction, operation, and eventual decommissioning of the capture, transportation and storage facilities, manufacture and regeneration of chemicals, as well as their eventual disposal along with other waste products, also have environmental impacts, both in terms of CO2 emissions and also across a broad spectrum of other environmental factors. To correctly evaluate the environmental impact of CCS technologies, and particularly to compare the relative benefits of different technologies (e.g., a new NGCC power plant vs a coal-fired plant with CCS), it is therefore important to consider the full life cycle of the integrated system. This approach, known as life-cycle analysis or assessment (LCA), is illustrated schematically in Figure 2.6. A common functional unit for LCA of power generation systems is the GWh while for a CCS EOR project it might be an incremental barrel (bbl) of oil production. An important consideration in defining system boundaries is how far up- and

34

Carbon Capture and Storage

Define LCA objectives and functional unit

Define system boundaries

The functional unit is the quantity of output from the overall process under consideration which is used as the denominator in assessing impact (e.g., 1 GWh of electrical energy output, 1 t-cement produced, etc.). The system boundaries define those elements of the overall industrial process chain that are included in the analysis (e.g., how far upstream into raw materials production and downstream into end product use).

Determine inputs and outputs of all included activities/processes

Inputs and outputs of subsidiary processes that lead to the production of one functional unit are inventorized in terms of the quantities required to produce one functional unit of output of the overall process.

Determine overall environmental impact from activity/process inputs and outputs

The environmental impact of each subsidiary input and output is assessed across a range of impact categories, typically from existing databases, and may be normalized to assess the overall life cycle impact of the system in producing one functional unit of output.

Interpretation of LCA results

Summary and evaluation of the LCA outcome, identifying the level of confidence in the outcome and the key factors influencing it, as well as conclusions and recommendations.

Figure 2.6 Schematic representation of the life-cycle assessment (LCA) process.

Coal mining

Coal mining operations Coal transportation

Electricity generation

Generation plant construction, operation, and decommissioning

Post-combustion capture

CCS plant construction, operation, and decommissioning

CO2 transportation

CO2 pipeline construction, operation, and decommissioning

CO2-EOR storage

Injection well construction, operation, and decommissioning, including CO2 separation and recompression

Oil refinery Product end-use

Refining operations for incremental oil recovery

Possible system boundary for comparison of CCS versus natural CO2 supply for EOR

Possible system boundary for comparison of CCS–EOR versus CO2 use in biofuel production from algae

Use of refined products from incremental oil recovery (e.g., transportation)

Figure 2.7 Schematic of system boundary options for LCA of a CCS EOR project.

downstream to take the assessment. For example, while it is clear that the impact of materials (e.g., cement, steel) used in the construction of a CCS plant or the production and transportation of wood chips for biomass co-firing would be included in the assessment, it is less obvious whether the end-use of the incremental barrel of oil or GWh of electrical energy should also be included. Figure 2.7 illustrates such

Overview of carbon capture and storage

35

Table 2.4 Sub-set of the Eco-indicators 99 impact classification Impact class/category

Description

Human health Global warming potential Ozone layer depletion Carcinogenics Respiratory organics/ inorganics

Impact of emissions on radiative forcing Impact of emissions on ozone layer Impact of carcinogenic substance emission on human health Impact of organic and/or inorganic substance emissions on human respiration

Ecosystem quality Eco-toxicity Acidification Eutrophication Land use

Impact of toxic substances on freshwater, soils, etc. Impact of acid-forming emissions on oceans, rainwater, etc. Impact of excessive nutrient supply Land use requirement of the element under evaluation

Resources Fossil fuel depletion Mineral depletion Consumptive water use Degradative water use

Impact of activity on fossil fuel resources Impact of activity on mineral resources Water consumption in executing the activity Volume of degraded water resulting from the activity

a system boundary choice when comparing a CCS EOR project with other CO2 source or usage options. (Note that the process/activity maps for the alternative options are not shown, but would also need to be constructed.) A robust definition of the LCA objectives should provide the basis for resolving such issues. Impacts of each activity within each process (e.g., manufacture of steel used in CCS pipeline construction) are assessed against a standard set of impact classes, of which the Eco-indicators 99 set is a commonly used example. A sub-set of this classification is shown in Table 2.4. Quantitative impact values (e.g., m3 water use/t-steel produced) are available from a range of databases and software systems. Interpretation of LCA results rarely boils down to a single number demonstrating the comprehensive superiority of one option over another. Trade-offs (e.g., reduced global warming potential vs increased eco-toxicity) should be kept visible and results presentations should also include an assessment of the sensitivity of conclusions to uncertain input data.

2.4

References and resources

2.4.1 References Abanades, J.C., et al., 2015. Emerging CO2 capture systems. Int. J. Greenhouse Gas Control. 40, 126 166. Cue´llar-Franca, R.M., Azapagic, A., 2015. Carbon capture, storage and utilisation technologies: a critical analysis and comparison of their life cycle environmental impacts. J. CO2 Util. 9, 82 102.

36

Carbon Capture and Storage

De Coninck, H., Benson, S.M., 2014. Carbon dioxide capture and storage: issues and prospects. Annu. Rev. Environ. Resour. 39, 243 270. Dooley, J., 2013. Estimating the supply and demand for deep geologic CO2 storage capacity over the course of the 21st century: a meta-analysis of the literature. Energy Procedia. 37, 5141 5150. Gibbins, J., Chalmers, H., 2008. Carbon capture and storage. Energy Policy. 36, 4317 4322. IEA, 2013. Carbon capture and storage—Technology Roadmap. Available at www.iea.org/ publications/freepublications/publication/technologyroadmapcarboncaptureandstorage.pdf. IEA/OECD, 2004. Prospects for CO2 Capture and Storage. OECD, Paris, France. Available at http://ccs-info.org/onewebmedia/iea_oecd_ccs_prospects.pdf. IPCC, 2005. Special Report on Carbon Dioxide Capture and Storage. Cambridge University Press, Cambridge, UK. Leung, D.Y.C., Caramanna, G., Maroto-Valer, M.M., 2014. An overview of current status of carbon dioxide capture and storage technologies. Renewable Sustainable Energy Rev. 39, 426 443. Odeh, N.A., Cockerill, T.T., 2008. Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage. Energy Policy. 36, 367 380. Zapp, P., Schreiber, A., Marx, J., Haines, M., Hake, J.-F., John Gale, 2012. Overall environmental impacts of CCS technologies—a life cycle approach. Int. J. Greenhouse Gas Control. 8, 12 21.

2.4.2 Resources Eco-indicator 99 LCA manuals (Pre-consultants): www.pre-sustainability.com/eco-indicator99-manuals. Global CCS Institute. 1. CCS project database: www.globalccsinstitute.com/projects/large-scale-ccs-projects. 2. Annual summary report on CCS status: https://hub.globalccsinstitute.com/sites/default/ files/publications/201158/global-status-ccs-2016-summary-report.pdf. IEA, 2016. 20 Years of Carbon Capture and Storage—Accelerating Future Deployment. Available at www.iea.org/publications/freepublications/publication/20-years-of-carboncapture-and-storage.html. MIT CCS project database (a useful reference but no longer maintained since September 2016): https://sequestration.mit.edu/tools/projects. US Department of Energy National Energy Technology Laboratory. 1. CCS project database: www.netl.doe.gov/research/coal/carbon-storage/strategicprogram-support/database. 2. Carbon Sequestration Newsletter (newsletter covering CCS news and newly published literature): www.netl.doe.gov/research/coal/carbon-storage/carbon-storage-newsletter. 3. Library (links to NETL Carbon Capture, Compression and Storage Program documents and reference materials): www.netl.doe.gov/library.

Power generation fundamentals

3

Carbon capture from fossil fuel
burning power-generation plant will be a necessity if carbon capture and storage is to make a material impact on total anthropogenic emissions. It is also an area where the opportunity exists for a rapid reduction of emissions, because some key technologies have been developed and deployed in other industries. As a precursor to the discussion of capture technologies in Part II, the fundamentals of fossil-fueled power generation are described in this chapter. This begins with a review of the chemistry of combustion and gasification, the physics of the thermodynamic cycles used in standard and combined cycle power plants (the Rankine steam cycle and the Brayton gas turbine cycle), and a discussion of some relevant aspects of the metallurgy of steel. The components and processes of a typical fossil-fueled power plant and a combined cycle plant are then described.

3.1

Physical and chemical fundamentals

3.1.1 Fossil fuel combustion The combustion of fossil fuels remains the primary energy source for power generation worldwide, providing around 85% of the global primary energy supply. The typical characteristics and compositions of fossil fuels, in the order of their importance for power generation, are shown in Table 3.1, while those for some biomass fuels are shown in Table 3.2. Combustion converts the chemical energy of the fuel to heat through a series of exothermic reactions. The general form of the reaction for the complete combustion of a hydrocarbon is: Cx Hy 1 ðx 1 y=4ÞO2 ! xCO2 1 ðy=2ÞH2 O 1 heat

(3.1)

For example: C 1 O2 ! CO2 1 heat

ΔH 5
383:8 kJ=mol C

CH4 1 2O2 ! CO2 1 2H2 O 1 heat

ΔH 5
800 kJ=mol CH4

(3.2) (3.3)

The enthalpy of combustion (ΔH; see Glossary)—essentially the exothermic energy released—measures the enthalpy change when one mole of the fuel is fully oxidized and is quoted at 25 C (298K) unless otherwise stated. For combustion of Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00003-9 © 2017 Elsevier Inc. All rights reserved.

38

Carbon Capture and Storage

Table 3.1 Typical heating value and composition of fossil fuels Fuel

Heating value (LHV MJ/kg)

Composition (wt% dry) C

Coal (lignite) Coal (anthracite) Natural gas (Groningen) Crude oil Peat

17.7 33.9 38.1 18.5 22.6

H

O

S

49.8 3.3 27.7 88.9 3.4 2.3 58 18.7 1.5 88 8.2 0.5 56.7 6.0 35.9

N

Ash

0.5 1.0 17.7 0.8 1.6 2.9 0 21.6 0 3 0.1 0.2 0.2 1.7 4.9

Table 3.2 Average heating value and composition of biomass fuels Fuel

Heating value (LHV MJ/kg)

Wood Grass/plants Manure Straw Algae

18.7 18.3 18.9 18.0 24.8

Moisture content (wt%) 18.6 29.8 44.0 14.6 31.9

Composition (wt% dry) C

H

O

S

N

Ash

50.7 49.2 47.2 48.7 53.8

6.1 6.0 6.5 6.0 7.4

42.8 43.4 36.4 43.3 30.9

0.1 0.2 0.7 0.2 0.5

0.4 1.2 5.0 0.9 7.5

2.2 6.9 28.5 7.5 6.1

carbon in Equation (3.2), this translates to release of 1 MWh of thermal energy for the combustion of 9400 moles (113 kg) of carbon or 414 kg-CO2/MWh of thermal energy. In practice, CO2 emissions from fossil fuel power generation range from 600 to 1200 kg-CO2/MWh of delivered energy. As well as the oxidation of the carbon or hydrocarbon, other components of the fuel will also be oxidized during combustion: S 1 O2 ! SO2 1 heat

ΔH 5
296:8 kJ=mol

(3.4)

N 1 O2 1 heat ! NO2

ΔH 5 1 33:1 kJ=mol

(3.5)

2N 1 O2 1 heat ! 2NO

ΔH 5 1 90:3 kJ=mol N

(3.6)

The latter two reactions are endothermic (heat input is required).

Partial oxidation Equation (3.1) expresses the stoichiometric requirement for complete combustion of the fuel. Partial combustion, or partial oxidation (POX), occurs if oxygen

Power generation fundamentals

39

availability in the reaction zone is less than the stoichiometric requirement for full oxidation and is important in gasification, as discussed in the next section. The general equation is: Cx Hy 1 ðx=2 1 y=4ÞO2 ! xCO 1 ðy=2ÞH2 O 1 heat

(3.7)

For example: C1

1 O2 ! CO 1 heat 2

CH4 1

ΔH 5
123:1 kJ=mol C

1 O2 ! CO 1 2H2 1 heat 2

ΔH 5
38:0 kJ=mol CH4

(3.8)

(3.9)

Heating value of a fuel The heating value of a fuel can be expressed either as a higher heating value (HHV) or a lower heating value (LHV). This measures the amount of heat released when a quantity of fuel, initially at 25 C, is combusted and all combustion products are cooled either to 25 C in the case of the HHV or to 150 C in the case of the LHV. The difference between the two values is therefore due to the difference in heat content of the combustion products between the two end temperatures including the latent heat of vaporization of any steam resulting from moisture in the fuel and from water formed by the combustion of hydrogen in the fuel. The thermal efficiency of a plant is typically referenced to the LHV of the fuel, except where waste heat is recovered down to low temperatures, such as in CHP plants.

Oxyfueling The reaction products shown in Equations (3.1)
(3.9) reflect combustion in oxygen although, in traditional power plants, oxygen is just one component of the air blown into the furnace. A more accurate representation of Equation (3.2) would therefore be: C 1 O2 1 3:73 N2 ! CO2 1 3:73 N2 1 heat

(3.10)

Separation of CO2 from this reaction product stream is the essence of the post-combustion carbon capture problem. Oxyfuel combustion, or oxyfueling, sidesteps this separation problem by burning the fuel using pure oxygen rather than air, thereby adhering strictly to Equation (3.2). The combustion gases then comprise CO2, steam, and possibly SOx and NOx, depending on the S and N content of the fuel. Steam can be separated by condensation, with recovery of the low-grade heat, and the remaining dried gas can be further treated if required and compressed for transportation and storage.

40

Carbon Capture and Storage

Technologies for air separation to generate oxygen for oxyfueling are described in Part II and include membrane-based (Section 8.5) and cryogenic systems (Section 9.3).

3.1.2 Gasification of fossil and other fuels An alternative to fully releasing the chemical energy of the fuel—whether coal, oil, gas, or biomass—through complete combustion is to gasify the fuel to produce an intermediate synthesis gas product (syngas), which can then be used as a feedstock for the production of liquid fuel, hydrogen, or methanol. Syngas is a mixture of CO and H2 and results from the partial combustion of carbon and its high-temperature reaction with steam, according to the reactions shown in Table 3.3. Any CO2 present under partial oxidation conditions will be converted to CO via the Boudouard reaction, shown in the table, particularly at high temperatures which shift the equilibrium of this reaction to the right.

3.1.3 Syngas production from methane Syngas can also be produced from methane either by partial oxidation (Equation (3.9)) or by steam reforming according to the reactions shown in Table 3.4. The partial oxidation reaction takes place at temperatures above 1200 C to drive the reaction equilibrium toward the partial oxidation products and requires a hightemperature catalyst in order to achieve a high reaction rate. The 2:1 H2:CO ratio of the partial oxidation reaction products provides the optimal feed for gas-to-liquids conversion such as the Fischer
Tropsch process. Table 3.3 Carbon-based feedstock gasification processes and reactions Process

Reaction

Partial oxidation

1 O2 ! CO 2 C 1 H2 O ! CO 1 H2 C 1 2H2 O ! CO2 1 2H2 CO 1 H2 O2CO2 1 H2 C 1 CO2 22CO

Carbon
steam reaction Water
gas shift (WGS) reaction Boudouard reaction

C1

Table 3.4 Syngas production by steam reforming of methane Process

Reaction

Partial oxidation

1 O2 ! CO 1 2H2 2 CH4 1 H2 O ! CO 1 3H2 CO 1 H2 O2CO2 1 H2

Steam methane reforming WGS reaction

CH4 1

Power generation fundamentals

41

Catalytic steam reforming of methane is the most important process used for syngas production, the reaction taking place in catalyst-packed reactor tubes operating at pressures of 1.5
4.0 MPa and temperatures of 700
950 C. Steam reforming of methane produces a 3:1 H 2:CO ratio in the product stream, which is too hydrogen rich for liquid synthesis processes. This can be modified using the water-gas shift in a separate reactor at temperatures of 300
500 C, reducing the H 2:CO ratio as the WGS equilibrium shifts to the left. Alternatively, at higher temperatures, as the equilibrium shifts to the right, a H2 1 CO2 reaction product stream results, from which the CO2 can be removed to generate hydrogen. This process is used for hydrogen production in refineries as a hydrocracker feed, with amine absorption to remove CO2 from the product stream, and is also used for the generation of hydrogen from natural gas as a carbonfree transport fuel.

3.1.4 Thermodynamic cycles A thermodynamic cycle is a sequence of changes in the state of a thermodynamic system such that at the end of the sequence all properties of the system are returned to their initial values. Examples of a change would be the addition of heat to a working fluid such as water in a boiler, or allowing a working fluid such as steam to expand through a turbine. If the cycle results in the transfer of energy from a hot source to a cold sink and conversion of part of that energy to work, the system is termed a heat engine. Thermodynamic cycles are described and analyzed using the temperature
entropy (T-S) or pressure
volume (P-V) diagrams of the working fluid, as shown in Figure 3.1 for water. G P2 F

Liquid region

Bub ble po int

li

ne

E

D

Critical point PC

De w

Liquid + vapor region

P1 e lin int po

Temperature

TC

Vapor region

T1 B

C

A Freezing temperature Solid + vapor region Entropy

Figure 3.1 Temperature
entropy (T-S) diagram for water.

42

Carbon Capture and Storage

Above the freezing temperature of water, three regions are shown on the T-S diagram: G

G

G

The liquid region, to the left of the bubble point line. Points on the T-S diagram in this region represent 100% liquid water at varying temperature (T) and pressure (P). The vapor region to the right of the dew point line. In this region water exists as 100% vapor (steam) at varying T and P. The intervening liquid
vapor region, where points represent varying water
steam mixtures, from 100% liquid at the bubble point line to 100% vapor at the dew point line.

The line ABCD represents a thermodynamic process in which, at constant pressure P1, a quantity of water is heated to the boiling point (T1) at this pressure (A to B), is fully vaporized (B to C), and is then superheated above the boiling temperature (C to D) while still at pressure P1. The point where the bubble point and dew point lines meet is called the critical point and represents the temperature (Tc) and pressure (Pc) above which the transition from liquid to vapor occurs without a discernible change of state and without any intervening mixed liquid-plus-vapor state. A thermodynamic process operating at temperatures and pressures above the critical point is termed supercritical (SC). Line EFG in the figure shows the T-S curve for a quantity of fluid at a pressure P2, greater than Pc, being heated to the critical temperature (E to F) and then superheated (F to G). Steam generators operating at SC and ultrasupercritical (USC) conditions (see Glossary) are an important area of technology development to improve the thermal efficiency of fossil-fueled power plants (Section 3.2.3). The simplest ideal thermodynamic cycle, the Carnot cycle, is illustrated in Figure 3.2 on T-S and P-V diagrams, and consists of four thermodynamic processes: 1. From A to B: a reversible isothermal expansion of the working fluid, with heat being drawn from the hot source at temperature TH (K) 2. From B to C: an isentropic (reversible adiabatic) expansion of the working fluid, delivering work, for example, to a turbine

TH

B Pressure

Temperature

A A

TC

D

B

TH

D

C C E

F SC

SD Entropy

Figure 3.2 The Carnot thermodynamic cycle.

Volume

TC

Power generation fundamentals

43

3. From C to D: a reversible isothermal compression of the working fluid, with heat transfer out of the system to the low-temperature sink at temperature TC 4. From D to A: an isentropic compression of the working fluid. Work is done to compress the working fluid, resulting in a rise in temperature from TC to TH, at which point the ideal system has returned to its initial state.

In the cycle shown in Figure 3.2, the area CDEF, equal to TC(SC 2 SD), is the amount of heat exchanged with the cold sink (QC) while the area ABFE, equal to TH(SC 2 SD), is the heat absorbed from the hot sink (QH). The difference between these is the energy transferred from the system as work (W): W 5 ðTH
TC ÞðSC
SD Þ

(3.11)

and the Carnot efficiency (ηCarnot), defined as the amount of work done divided by the heat exchanged with the hot source, is: ηCarnot 5 W=QH 5 ðTH
TC Þ=TH 5 1
TC =TH

(3.12)

temperatures here being measured in K. The Carnot efficiency represents the theoretical limit for perfectly reversible systems where all heat input and output are done at the hot and cold reservoir temperatures. In practice, processes such as compression, expansion, and heat transfer are irreversible, and various other energy losses through friction, radiation, and leakage prevent the Carnot efficiency from being achieved in practice. Directionally, the Carnot efficiency is increased as the ratio TH/TC is increased, which is also true for practical cycles, a simple example of this being the roughly 2-percentagepoint higher efficiency of fossil-fueled power plants on coastal sites, where seawater is available for cooling, compared to those inland. Several further examples will be discussed in the following section, including combined cycles, which reduce the final temperature TC of heat rejection, as well as SC and USC steam cycles, which increase TH.

Rankine steam cycle The Rankine cycle is the ideal cycle that describes a heat engine using water and steam as the working fluid and is the cycle that applies to power generation using a steam turbine. Figure 3.3 illustrates schematically the physical components of a Rankine heat engine and the T-S diagram of the cycle. The four thermodynamic processes that make up the cycle are as follows: 1. From A to B: High-pressure feedwater is heated in a boiler by the combustion of fuel. At point B, on the dew point line, the working fluid has become dry saturated steam. 2. From B to C: The saturated steam is expanded through a steam turbine. Work is delivered to the turbine shaft, with the drop in pressure and temperature likely bringing the working fluid inside the dew point line, resulting in some condensation. 3. From C to D: The wet steam is cooled in a condenser, and heat is transferred to a cooling medium. The working fluid is returned fully to the liquid state. 4. From D to A: Water is pressurized by a feed pump before reentering the boiler.

44

Carbon Capture and Storage

QB

HB

Turbine

HA

Pump WFP

HD

HC Condenser

Temperature

Boiler

WT

Boiling point at operating pressure

Critical point B

A D

C

QC Entropy

Figure 3.3 Rankine cycle heat engine and T-S diagram.

In Figure 3.3, HA, HB, HC, and HD measure the enthalpy (H 5 TS 1 PV) carried by the working medium into the boiler, turbine, condenser, and feed pump, respectively, WT is the net shaft work delivered from the turbine and WFP is the work delivered to the feed pump, QB is the external heat delivered to the boiler from the furnace, and QC is the heat rejected to the condenser cooling medium. The efficiency of the Rankine cycle can be derived as follows: ηRankine 5 ðWT
WFP Þ=QB

(3.13)

Since WFP/QB  0, this reduces to: ηRankine 5 WT =QB 5 ðHB
HC Þ=ðHB
HA Þ

(3.14)

The overall efficiency can be improved by reducing losses and recovery of lowgrade heat from flue gases and from the condenser cooling medium (i.e., from QC), for example, to pre-heat feedwater. The efficiency is also improved by increasing both the temperature and pressure of steam driving the turbine, since either of these will increase the enthalpy at the turbine inlet (HB). This leads to the use of superheated, reheated, and SC steam cycles, as illustrated in Figure 3.4. Superheating (Figure 3.4A) increases the temperature of dry steam leaving the boiler, resulting in an increase in turbine work (WT) and also has the practical advantage of reducing condensation within the turbine, since point C is moved closer to the dew point line. Cycle efficiency is also raised since the additional heat input to the working fluid is occurring at a higher temperature. Reheating (Figure 3.4B) adds additional heat from the boiler to steam between the highpressure and low-pressure sections of the turbine, with similar improvement in turbine work but at a lower incremental efficiency. An SC steam cycle (Figure 3.4C) operates at a steam pressure and temperature above the critical point (22.1 MPa, 374 C) with higher thermal efficiency. To achieve

Power generation fundamentals

45

(A)

(B) B Temperature

Temperature

B

A

C

D

C

A

F

E

Entropy

Entropy

(C)

Temperature

D

B

A D

C Entropy

Figure 3.4 T-S diagrams for (A) superheated, (B) reheated, and (C) SC steam cycles.

this, special high-cost materials are required to withstand the extreme conditions, particularly in the furnace wall, as described in Section 3.1.7.

Brayton gas turbine cycle The Brayton cycle is the ideal thermodynamic cycle that describes the operation of a closed-loop system comprising a compressor, a combustion chamber, and a turbine, as illustrated in Figure 3.5. The operation of the cycle involves four process steps: 1. From A to B: Air is drawn into a compressor and undergoes isentropic compression. 2. From B to C: The air is mixed with fuel and combusted in a combustion chamber at constant pressure. 3. From C to D: The combustion products are expanded through a turbine and work is extracted via the turbine shaft. 4. From D to A: The loop is closed by the rejection of heat from the turbine exhaust gas to an ambient temperature cold sink.

The efficiency of the ideal Brayton cycle is given by: ηBrayton 5 1 2 TA =TB 5 1 2 rpðγ21Þ=γ

(3.15)

46

Carbon Capture and Storage

C

QH Combustion chamber

Isentropic C turbine

PC

PC QH

Temperature

Isentropic compressor B

WT

B D QL

PD Cooler

A QL

D

PD

A Entropy

Figure 3.5 Brayton cycle heat engine and T-S diagram.

QC

QR C

B

D

Reheat combustor

Combustor

Compressor

Turbine 1

B Compressor 1

E

Compressor 2

Turbine 2 Inter-cooler

A A

F

(A)

Qout

A2

(B)

QC

QR

D F

B F⬘ A Entropy

QH

E Temperature

C Temperature

A1

A1⬘

B

A1 A2

Qout

QL A Entropy

Figure 3.6 Process schematics and T-S diagrams for (A) reheated and (B) inter-cooled Brayton cycles.

where rp is the ratio of the inlet and outlet pressures of the turbine (PC/PD) and γ is the ratio of the specific heats of the gas for constant pressure and constant volume processes (γ 5 Cp/Cv). Similar to the use of superheating and reheating in the Rankine cycle, the work output from a Brayton cycle can be increased by reheating, in which the exhaust from the first gas turbine is reheated in a second combustion chamber and drives a second turbine (Figure 3.6). Reheating allows additional heat input to the turbine without exceeding the maximum temperature limit determined by the rotor material, but the overall cycle

Power generation fundamentals

47

Cooler

QL

Regenerator

QH

QH,R Reheater

Combustion

WT Compression stages

Turbine stages Intercooler

QLI

Figure 3.7 Brayton process schematic with reheating, inter-cooling, and regeneration.

efficiency is reduced because, as can be seen from the T-S diagram, heat rejection for the second part of the cycle (F
F0 in Figure 3.6A) occurs at a higher temperature than the original cycle. Inter-cooling splits compression into two stages, cooling the working fluid between stages. An increase in cycle efficiency can be achieved since a higher pressure can be achieved with the same compressor outlet temperature. Regeneration (or recuperation) recovers heat from the turbine exhaust to pre-heat gas entering the combustion chamber. The amount of heat recovered can be increased by increasing the turbine exhaust temperature and by reducing the compressor outlet temperature. The impact of regeneration on overall thermal efficiency is therefore maximized when applied in combination with reheating and inter-cooling. Figure 3.7 illustrates a Brayton cycle process with reheat, inter-cooling, and regeneration. Other approaches to increasing the power output level of a Brayton cycle, generally at higher thermal efficiency than the standard cycle, include injecting steam into the gas turbine combustion chamber (STIG) and the use of humid air as the turbine working fluid (HAT).

3.1.5 Aspects of steel metallurgy for fossil-fueled power plants Since the live steam temperature is the key factor that determines the thermal efficiency of the Rankine steam cycle (Equation (3.14)), the quest for higher cycle efficiency boils down to a quest for materials capable of operating under ever higher temperatures and pressures and under the corrosive conditions of a steam boiler. Stainless steel is the principal construction material for boiler and turbine components, and the three main types of steel—ferritic, austenitic, and martensitic (see Glossary)—each has advantages in particular power plant applications (Table 3.5). The two key properties of steel that are essential in high-temperature, highpressure, corrosive environments are strength, particularly creep strength, and corrosion resistance. Slow thermally activated creep of components under load can eventually lead to rupture or excessive plastic deformation. A creep strain

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Carbon Capture and Storage

Table 3.5 Advantages and disadvantages of various steel types Steel type

Composition

Advantages

Ferritic steels

Fe
Cr alloy steels with 10%
25% Cr, 2%
4% Mo, ,1% Ni, and ,0.75% C

Austenitic steels

Fe
Cr
Ni alloys with 16%
25% Cr, 1%
37% Ni, and ,0.24% C

Lower thermal expansion Alloying (e.g., tungsten and vanadium) coefficient resulting in required to overcome lower thermal stresses low creep strength of under cyclic operation, conventional ferritic particularly for thicksteels walled components High corrosion resistance Higher thermal expansion and low —important in creep strength for corrosive service such high-temperature as refuse incineration service boilers High creep resistance as Poorer corrosion resistance, which can a result of the be improved by microcrystalline precipitation structure hardening; more brittle

Martensitic Fe
Cr alloys with steels 12%
18% Cr and ,1% C; may also include up to 2% Ni, Mo, V, or W

Disadvantages

limit of B3 3 10211/s is not uncommon and would result in a dimensional elongation of B2% after a typical 30-year service life. Corrosion resistance must address both the fire-side and steam-side environments and, on the fire side, the impact of different fuels used in the furnace.

Corrosion resistance The oxidation resistance of steel is primarily a result of the chromium content, and to a lesser extent, in austenitic steels, the high nickel content. Chromium on the steel surface is oxidized to form an invisibly thin layer of chromium oxide (Cr2O3), and this so-called passivation layer will be quickly reformed if damage occurs, provided the bulk chromium content remains above a threshold value of B7%. Cracking of the protective layer can occur as a result of creep or thermal cycling, and the presence of water vapor then leads to the formation of volatile chromiumcontaining hydroxyl species and a loss of chromium from the steel through evaporation. A chromium content well above the 7% threshold is therefore essential for long-term service under corrosive conditions. Further alloying can improve corrosion resistance; the addition of silicon aids in the process of crack healing in the passivation layer, manganese slows chromium evaporation loss as a result of the formation of a hard manganese
chromium (MnCr2O4) spinel layer (see Glossary), while tungsten and other metals increase creep strength as a result of carbide formation.

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Table 3.6 Carbide, nitride, and boride precipitates Precipitate

Composition

Carbides MC M3C M7C3 M23C6 M6C

(Ti,Nb,V)C (Fe,Mn,Cr)3C (Fe,Cr)7C3 (Fe,Cr,Mo)23C6 (Fe,W,Mo,Nb,V)6C

Nitrides MN M2N

(Ti,Nb)N (Fe,Cr)2N

Borides M2B M3B2

(Fe,Cr)2B (Fe,Cr,Mo)3B2

Carbides, creep, hardening, and embrittlement A key process that determines the strength and thermal creep resistance of steel is the precipitation of carbides, and in some cases nitrides or borides, that occurs during the initial cooling or subsequent heat-treating of steel, the latter process also known as precipitation hardening. The solubility of carbon in an Fe
Cr
Ni austenitic steel declines from 0.15% by weight to less than 10 ppm as the steel is cooled to B600 C. As a result, carbon comes out of solution during cooling, resulting in the formation of carbides of Fe, Cr, Mo, Mn, Nd, etc., depending on the alloying metals present in the steel. Steels containing nitrogen or boron will also precipitate nitrides and borides. Some common precipitates are summarized in Table 3.6, where M represents the metal alloy atom. As well as primary precipitation, which occurs during solidification and typically produces precipitate particles in the 1
10 μm size range, secondary precipitation also occurs during heat-treating or as a result of cycling in high-temperature service and results in smaller precipitate particles in the 5
50 nm range. The most stable MC carbides nucleate predominantly on dislocations and stacking faults within crystal grains and are beneficial because they prevent creep by locking and preventing the movement and growth of these crystal defects that lead to creep. In contrast, M23C6 carbides tend to nucleate on grain boundaries and result in chromium depletion and increased susceptibility to inter-granular corrosion. This detrimental formation of M23C6 can be reduced by the addition of Ti or Nb, which encourage MC precipitation, or by the addition of nitrogen, which promotes the precipitation of M6C-type carbides. Similar to the MC carbides, secondary intragranular precipitation of very fine complexes such as NiAl, Ni3Al, Ni3Ti, Ni3Nb, and

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Carbon Capture and Storage

Ni3Cu during heat treatment can also lead to increased strength, through precipitation hardening. In high-temperature service, steel components experience repeated temperature cycling through the temperature range where these precipitation processes are active. As a result the crystal structure of a steel component is continually changing throughout its service life due to dissolution, transformation, and reprecipitation. For example, continued growth of the inter-metallic NiAl-type complexes that result from precipitation hardening can occur in high-temperature service and can lead to a decline in the strength of the material since dislocations are no longer locked once these particles exceed a certain size relative to the lattice spacing. Carbide precipitates will also coarsen during service, and more rapidly at high temperatures when the diffusivity of impurities is increased, providing sites for crack formation. This process is known as grain boundary embrittlement.

3.2

Fossil-fueled power plants

3.2.1 Introduction The process diagram of a typical pulverized coal power plant, embodying the physical and chemical fundamentals discussed above, is shown in simplified form in Figure 3.8. The pulverized fuel is blown into the furnace by a draft of air, which is preheated in a heat exchanger by flue gas exiting the boiler. Initial boiling takes place Electric power

HP turbine

Coal

Coal handling

Coal milling

IP turbine

LP turbine

Steam to and from turbine stages

Generator

Condenser Feed water

Boiler furnace

Superheater

Reheater

Feed water heating

Economizer

Bottom ash Air

Air heater

NOx reduction Flyash removal

Fly ash

Flue gas treatment

Flue gas

Sulfur removal Sulfur

Figure 3.8 Process diagram for pulverized coal (PC)-fired power plant.

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51

in the water-cooled wall of the furnace, and the final steam temperature to drive the high-pressure (HP) steam turbine stage is achieved in a superheater. HP turbine exhaust steam is reheated (first reheat) to drive the intermediatepressure (IP) turbine stage and may be reheated again (second reheat) to drive the low-pressure (LP) stage. The three turbine stages are linked by a single shaft to the generator. Exhaust steam from the LP stage is condensed using a cooling water supply, pressurized, and pre-heated in a heat exchanger (the economizer) before reentering the boiler. Following a NOx reduction step, the final stage of heat recovery from the flue gas is used to heat the boiler air supply. Fly ash removal and desulfurization complete the flue gas treatment before emission. The following sections describe each of the main process steps. Although the emphasis is on PC firing, which dominates new installed plant capacity, variations to cater for other fuels, particularly syngas and biomass, are also described.

3.2.2 Fuels and fuel handling Coal firing In coal-fired power plants, the traditional mechanically stoked furnace, in which a layer of chunk coal burns on a grate, has been largely superseded by the combustion of pulverized fuel, which is blown into the furnace by a pre-heated air draft. The fuel is prepared by milling in a ball mill to produce a fine powder with 70%
75% of the fuel in particles less than 75 μm in diameter and less than 2% in particles .300 μm in diameter. Combustion takes place at 1300
1600 C for lowgrade coals and 1500
1700 C for higher grades, and particles typically spend only 2
5 s in the boiler before being deposited as bottom ash or, predominantly, carried out as fly ash in the flue gas stream.

Natural gas firing For fossil fuels other that coal, combustion of natural gas results in B50% less carbon emission per unit of heat generated compared to fuel oil, as a result of the higher H:C ratio of methane (CH4) versus the “average” hydrocarbon in fuel oil. Methane produces 1/2 CO2 per H2, while saturated hydrocarbons (CnH2n12) produce 2n/(2n 1 2) or roughly one CO2 per H2. Although natural gas can be used to fire a boiler for Rankine cycle steam generation, it is more commonly used as a fuel for gas turbine-driven generation, either in a simple Brayton cycle or more commonly in a variety of combined cycle configurations (see Section 3.3). For most natural gas compositions, no pre-treatment is required before combustion, although removal of acid gas (H2S and CO2), as well as water and hydrocarbon dew point control, may be required at the point of production if the gas is to be transported in a pipeline or liquefied.

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Carbon Capture and Storage

Gasification The gasification of coal or other carbonaceous feedstock, described above in Section 3.1.2, provides a flexible approach to fuel usage that has a number of advantages, including: 1. Wide range of feedstocks, including heavy oils and hydrocarbon residues, biomass, municipal solid wastes, or other refuse-derived fuel (RDF) 2. Adaptable for carbon capture 3. Production of a flexible intermediate fuel that can be used for direct firing as well as hydrogen or synthetic liquid production

As a fuel for direct firing, syngas can be used on its own to fire steam boilers or gas turbines and can also be combined in co-firing applications with natural gas or fuel oil.

Biomass co-firing Co-firing of biomass with coal has been introduced in order to reduce the CO2 intensity (kg-CO2/MWh) of coal-fired power generation, either as a result of direct legislation or by power companies seeking to meet lower emissions targets. Biomass may be introduced at the start of the fuel processing process so that the mixed coal 1 biomass fuel is handled using the existing processing and injection systems, or by the direct injection into the furnace of a separately processed biomass feed, either through the existing coal burners or through additionally installed biomass burners. The premixing option has the advantage of rapid implementation and low capital cost and is now well established at many large coal-fired plants, although it is generally limited to 5%
10% biomass on a heat input basis due primarily to limitation at the co-milling stage. This limitation can be overcome by direct injection co-firing, where the biomass is processed separately. Although the modification of existing coal burners for dedicated biomass injection has been successfully applied, the direct injection into existing coal firing systems has generally been preferred as a simple and lower-cost option. The main technical issues arising from biomass co-firing are increased fire-side corrosion of boiler materials, particularly with biomass feeds containing chlorine; reduction of the ash fusion temperature with addition of biomass ash (Section 3.2.5); and impact on ash handling as well as NOx and particulate control systems. As well as biomass, a range of RDFs may also be co-fired with coal, either in conventional furnaces, in fluidized bed combustors or gasified, as noted above.

3.2.3 Steam generation The steam generator consists of a furnace, in which heat is released from the fuel by combustion, and a boiler, in which the heat is transferred to water to create steam.

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53

Boiler technology In modern plants the functions of furnace and boiler are combined into a single unit in which a major stage of water heating is achieved by water-cooling the walls of the furnace, a so-called water wall or membrane wall.

Feedwater processing The purity and properties of the make-up feedwater are tightly specified in order to prevent scale deposition and corrosion, which increase maintenance costs and reduce boiler life. Raw feedwater is treated with chemical coagulants in settling tanks, followed by filtration to remove suspended solids. Dissolved salts are removed using chemical softeners and ion-exchange demineralizers (clays). Deaeration is achieved through multistage feedwater heaters, with residual oxygen removed to a few parts per billion (ppb) using oxygen scavengers such as hydrazine. Finally, the pH is controlled by chemical dosing to reduce acidity and avoid corrosion.

Evaporator design A key component of the subcritical boiler is the steam drum, in which steam and water exiting the water walls are separated, with water being recycled through the boiler together with makeup feedwater, while steam is further heated and piped to the HP turbine stage. In a boiler operating above the critical pressure, no phase change occurs as the feedwater is heated, so separation and recycling is not required, resulting is a so-called once-through design. The water wall in the combustion zone—the lower part of the boiler—consists either of vertical or spiral wound tubing, while vertical tubing is standard in the upper section where the heat flux is much lower. Vertical evaporator tubing is standard in drum boilers, but spiral wound tubing has the advantage that fewer parallel paths are required to cover the furnace wall, increasing the water mass flow rate through each tube, which ensures adequate cooling. In contrast, vertical tubes are internally ribbed to improve heat transfer. While spiral wound designs have become the standard in SC boilers, recent development of advanced tubing designs with internal rifling allows the advantages of vertical tubing (primarily lower manufacturing, installation, and maintenance costs) to be combined with the technical advantages of spiral configurations. The design that dominates the SC boiler market today, the Benson boiler, was patented in 1925 and is owned by Siemens AG (Figure 3.9). The operating conditions of a boiler are commonly expressed as: (live steam pressure/live stream temperature/first recycle steam temperature/second recycle steam temperature); for example, (31 MPa/610 C/565 C/540 C).

Superheating, reheating, and steam temperature control Superheating raises the temperature of steam exiting the evaporator to the operating temperature of the HP turbine stage. This increase in temperature is desirable as it increases the overall steam cycle efficiency (Section 3.1.5) and because the thermal energy delivered to the steam turbine by a given quantity of steam is also increased. Superheaters are heat exchangers located in the upper part of the furnace that bring

54

Carbon Capture and Storage

Hemweg Power Plant, Netherlands (261 bar/540°C/540°C)

Nordjyllandsvaerket Power Plant, Denmark (310 bar/582°C/580°C)

Lippendorf Power Plant, Germany (285 bar/554°C/583°C)

Figure 3.9 Schematic of Benson boilers—two pass and tower designs. Source: Courtesy Siemens AG.

the steam to its live operating temperature with heat transfer occurring both by convection and radiation. Reheaters, located downstream of the superheaters, reheat the exhaust steam from one turbine stage to provide additional energy to the next stage. Maintaining high overall plant efficiency under varying load conditions requires stream temperatures to be maintained within a narrow operating range. This is typically achieved using a spray attemperator, in which water is sprayed into the superheated steam to control the steam temperature, combined with either flue gas bypass or flue gas recirculation, which reduces either the quantity or the temperature of flue gas directed at the superheater. In a once-through boiler, the feedwater flow and firing rates are also coordinated to control steam temperature.

Condenser and heat recovery The thermal efficiency of the boiler (the fraction of energy released in combustion that is transferred to the steam) is a key factor determining the overall plant efficiency and is influenced by the temperature of gas exiting the heat recovery area (HRA), downstream of the furnace, and by the operating pressure of the condenser. As well as superheaters and reheaters, the HRA includes one or more heat exchangers, known as economizers, which pre-heat the condensed steam plus makeup feedwater between the condenser and the boiler. Further heat is recovered using a heat exchanger to pre-heat the air that will draft the furnace. In practice, reducing the temperature of the flue gas at the air heater exit to below the dew point temperature is not desirable to avoid acid corrosion resulting from the condensation

Power generation fundamentals

55

of water, and with conventional materials a boiler exit temperature of B130 C is typical.

Combustion technology Combustion technology covers the combustion chamber and burners for traditional furnaces, as well as new approaches such as fluidized bed and chemical cycling combustion.

Combustion chambers and burners A variety of combustion chamber and burner configurations are used for PC combustion, as shown in Figure 3.10. The choice is dictated by the fuel type and the attendant residence time required to achieve full oxidation of carbon in the fuel (burn-out).

Fluidized bed combustion In fluidized bed combustion a bed of coarse fuel particles, typically milled to B5
10 mm, along with other inert bed particles, commonly crushed limestone or dolomite, is fluidized by an upward-flowing stream of combustion air. If the air flow rate is sufficiently high the particles will be suspended in the circulating gas flow, resulting in a circulating fluidized bed (CFB). At lower air rates the bed will resemble a bubbling fluid—a bubbling fluidized bed (BFB). Figure 3.11 illustrates the configuration of BFB and CFB combustors. Fluidized beds have a number of advantages and disadvantages when compared to traditional PC combustion, the main ones being summarized in Table 3.7. Fluidized bed combustors cover a wide range of capacities: bubbling beds typically range up to 35 MWe, while circulating beds are common in the 100
460 MWe range, with some designs up to 800 MWe. CFB circulating velocities are typically 4
5.5 m/s, and 50
100 kg of solids are recycled through the bed for each kilogram of fuel burned. Pressurized bubbling and circulating fluidized beds (PBFB, PCFB), operating in the 1.0
1.5 MPa range, have also been developed and are similar to atmospheric Burner configuration Vertical section

Horizontal section

Burner type Fuel type

Tangential Lignite

Opposed Hard coal

Corner Hard coal

Figure 3.10 Combustion chamber configurations.

Slag tap Anthracite

Dry vertical Anthracite

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Carbon Capture and Storage

Flue gas cleanup

Flue gas cleanup Secondary cyclone

Bubbling fluidized bed

Cyclone separator

Circulating fluidized bed

Primary cyclone

Ash

Ash Fuel feed

Circulating bed medium

Fuel feed Gas heating

Air, O2

Gas heating

Air, O2

Figure 3.11 Fluidized bed combustion (FBC) configurations.

Table 3.7 Main advantages and disadvantages of atmospheric FBC FBC advantages G

G

G

G

G

Combustion at relatively low temperatures (800
900 C) with low NOx formation Efficient heat transfer from the bed to immersed heat transfer surfaces SOx can be removed within the combustor by adding limestone particles to the bed FBC combustors can be designed to cater for a wide range of fuel types, including low-grade coals, biomass, and wastes High combustion efficiency due to turbulent mixing and longer fuel particle residence time

FBC disadvantages G

G

G

Thermal efficiencies are B2%
4% lower than conventional PC combustion due to higher fan power and heat losses from the cyclones, as well as heat loss from the removal of ash and sorbent (e.g., if used for SOx control)

In-bed heat transfer surfaces, primarily in BFBs, are subject to erosion N2O formation is higher than in conventional PCC. Higher unburned fuel losses in CFBs, depending on fuel type

systems except that the combustor and cyclones are housed in a pressure vessel. The advantage of pressurizing the bed is that the high-pressure combustion gas can be used directly to drive a gas turbine, significantly improving overall thermal efficiency. However, the system also becomes much more complicated due to the need to pressurize the fuel, and air feeds, to depressurize the ash for removal, and possibly to filter the hot combustion gases to avoid erosion and deposition in the gas turbine system. Advanced PFBC combined cycle systems under development aim to raise thermal efficiency from the current (2017) 40%
45% to .50%.

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57

SC and USC steam operation Until the 1960s, power-plant steam generators traditionally operated at subcritical conditions, with live steam at 540 C and 18.5 MPa—below the 22.1 MPa critical pressure—and used a single reheat stage, commonly at the same temperature. The overall thermal efficiency that could be achieved at these conditions was B36%, although state-of-the-art subcritical plants can now reach 39% (LHV basis). By moving to higher-pressure SC conditions with live steam at 600 C and 30 MPa, an increase in efficiency to B45% could be achieved, approaching B50% with steam temperature .650 C. The first units operating SC steam cycles were commissioned in the late 1950s and early 1960s, with live steam at 605
610 C, two reheat cycles at 540
565 C, and operating at pressures of 31
32 MPa. USC operation is defined as a live steam temperature .600 C and pressure of 25
30 MPa, while advanced USC (A-USC) aims for 760 C and 35 MPa, the step-up from 600 C to 760 C potentially increasing plant efficiency by B9%. The maximum live steam temperature that can be achieved at a given operating pressure is determined by the availability of materials with the strength and gas-side corrosion and steam-side oxidation resistance required to construct the final superheater and reheater.

3.2.4 Steam turbine technology The steam turbine is the site of expansion and cooling in the Rankine steam cycle, where the energy contained in the steam is converted into mechanical work to drive an electrical generator. As shown in Figure 3.8, a large power plant will use one or more multistage steam turbines, with HP, IP, and LP stages. The LP stage in this conventional power application exhausts to a condenser at or slightly below atmospheric pressure, and this type of turbine is called a condensing turbine. In CHP or other applications where process steam is required, the LP stage may exhaust at a higher pressure (non-condensing turbine) or steam may be extracted from the turbine casing at an intermediate point (extraction turbine). Figure 3.12 shows the internal structure of a three-stage steam turbine. Each stage consists of one or more sets of fixed nozzles and moving rotor blades, with mechanical force being delivered to the moving rotors either by impulse or by reaction (Figure 3.13). In an impulse stage, commonly used in the HP and IP sections, the fixed nozzles direct jets of steam onto the bucket-shaped rotor blades. Expansion through the nozzles increases the steam velocity, and momentum is transferred to the turbine shaft as the impact of the jets on the rotor blades causes a change in direction of the steam jets. No change in pressure occurs across the moving rotor blades. The LP section is typically a reaction stage, in which expansion through the fixed nozzles again results in acceleration of the steam. In this case, however, the gaps between the rotor blades are also shaped like nozzles, and the transfer of momentum to the shaft is the result of both a change of direction of the steam and its acceleration relative to the rotor, due to expansion through these rotor nozzles.

58

Carbon Capture and Storage

Figure 3.12 Three-stage steam turbine internal structure with dual-flow IP and four-flow LP. Source: Courtesy Siemens AG.

Moving buckets Fixed nozzle

Rotor Rotating nozzle

Stator Rotor

Figure 3.13 Configuration of impulse (left) and reaction (right) turbine stages.

Roughly half of the overall pressure drop across a reaction stage is due to expansion over the moving rotor. Impulse stages tend to be more efficient in delivering work to the turbine shaft at higher pressures, while the two designs have similar efficiency at lower pressures.

Power generation fundamentals

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High-capacity steam turbines rated .500 MWe often have dual parallel flows in the IP section and may have two, four, or six flows in the LP section. These configurations are shown schematically in Figure 3.14. For advanced USC steam conditions, double reheat is used and a second IP stage, then called a reheat stage, is introduced, the second reheat section also being commonly dual flow.

3.2.5 Flue gas cleanup Ash and particulate removal In PC-fired furnaces, the temperature at which bottom ash fuses into a hard slag is an important design factor, since the buildup of slag leads to increased maintenance costs. While this can be avoided by operating the furnace at a temperature above the ash melting point (a so-called wet-bottom furnace), this leads to high NOx formation and is at odds with the now-common use of low-NOx burners. Modern PCfired furnaces maintain the ash in a dry state (dry-bottom) and bottom ash is removed through a hopper at the base of the furnace. Typically 70%
80% of the ash from PC combustion is fly ash, which leaves the furnace entrained in the flue gas. Electrostatic precipitators or bag filters (baghouses) are used to remove this and can achieve 99.9% ash removal down to levels of 1
2 mg/Nm3 of flue gas.

Flue gas desulfurization systems If small amounts of sulfur are present in the fuel, sulfur dioxide (SO2) will be formed during combustion and will therefore be present in the flue gas, with typical Superheated steam Single reheat Dual-flow LP section HP

IP

LP

LP

Reheater

LP heaters

Superheated steam Single reheat Dual-flow IP section Four-flow LP section HP

IP

IP

LP

LP

LP

LP LP heaters

Reheater Superheated steam

Dual reheat Dual-flow IP2 section Four-flow LP section HP

IP1

Reheater

IP2

IP2

LP

LP

Reheater

Figure 3.14 High-capacity steam turbine configurations.

LP

LP

LP heaters

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Carbon Capture and Storage

concentrations in the range of 400
2500 ppm, depending on the fuel. Sulfur trioxide (SO3) will also be present if the combustion temperature exceeds 800 C. The permitted emission levels of SOx are strictly controlled to prevent acid rain, which causes damage to terrestrial and aquatic ecosystems and corrodes building materials. Within the European Union, the SO2 emission limit for new liquid- or solid-fueled plants with capacities .300 MWth was established by the 2001 Revised Large Combustion Plant Directive at 200 mg/Nm3, while in the United States the New Source Performance Standard, established by the Environmental Protection Agency in 2006, specifies a SO2 emission limit of 0.64 kg/MWh for newly built plant, equivalent to 550 mg/Nm3 for a coal-fired plant emitting flue gas at B320 Nm3/GJ.

Wet scrubbing flue gas desulfurization process The most common method for SO2 removal, or flue gas desulfurization (FGD), is a wet limestone process in which a CaCO3 slurry is sprayed into a countercurrent flow of hot flue gas in an absorber tower. The alkaline solid reacts with the acid gas to produce calcium sulfite according to the reaction: Absorption: CaCO3ðsÞ 1 SO2ðgÞ 1

1 1 H2 O ! CaSO3  H2 OðsÞ 1 CO2ðgÞ 2 2

(3.16)

Air can also be blown into the absorber to oxidize the sulfite to sulfate: Oxidation: 1 2CaSO3  H2 OðsÞ 1 O2ðgÞ 1 3H2 O ! 2CaSO4  2H2 OðsÞ 2

(3.17)

This results in the unwanted pollutant being converted into a useful product, gypsum, which is marketed for use in the building industry. Other alkaline sorbents, such as magnesium hydroxide (Mg(OH)2), can also be used. In this case the resulting MgSO4 is regenerated by heating and sulfuric acid is produced as a marketable end product: Absorption: MgðOHÞ2ðaqÞ 1 SO2ðgÞ ! MgSO3ðaqÞ 1 H2 O

(3.18)

Oxidation: 2MgSO3ðaqÞ 1 O2ðgÞ ! 2MgSO4ðaqÞ

(3.19)

Precipitation: MgSO4ðaqÞ 1 7H2 O ! MgSO4  7H2 OðsÞ

(3.20)

Power generation fundamentals

61

Regeneration: MgSO4  7H2 OðsÞ 1 heat ! MgOðsÞ 1 SO3ðgÞ 1 7H2 O

(3.21)

SO3ðgÞ 1 H2 O ! H2 SO4ðaqÞ

(3.22)

Slaking: MgOðsÞ 1 H2 O ! MgðOHÞ2ðaqÞ

(3.23)

Wet scrubbing FGD can achieve 99% SOx removal, and the wet limestone process, producing gypsum, is expected to be the dominant technology for new-built plant in view of the ease of disposal of the end product.

Electron beam FGD A novel FGD approach uses a high-powered electron beam to ionize the main components of the flue gas stream (N2, O2, H2O, CO2) in an irradiation chamber. The resulting ionic species (N, O, OH, and HO2) react with SO2 to produce sulfuric acid: SO2 1 OH 1 M ! HSO3 1 M

(3.24)

HSO3 1 O2 ! SO3 1 HO2

(3.25)

SO3 1H2 O ! H2 SO4

(3.26)

where M is any inert molecule. Ammonia is sprayed into the flue gas upstream of the chamber and reacts with sulfuric acid to form ammonium sulfate: H2 SO4 1 2NH3 ! ðNH4 Þ2 SO4

(3.27)

The resulting solid product is collected using electrostatic precipitation and is also marketable, in this case as a fertilizer. An electron beam FGD installation on the 200 MWth EPS Pomorzany power plant at Szczecin in Poland uses electrons accelerated to an energy of 700 keV and a total beam power of 1.04 MW to treat 135,000 Nm3/h of flue gas, with an SO2 removal efficiency of 90%
95%.

NOx control and removal The NOx emitted in flue gases reacts with volatile organic compounds (VOCs) in the presence of sunlight to form ozone, which can adversely affect human health and causes damage to terrestrial ecosystems. NOx emissions limits in force in the European Union range from 200 to 600 mg/Nm3 (B166 to B500 ppm), depending on fuel type and plant capacity, with the lower level applying to plant .500 MWth.

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Carbon Capture and Storage

Untreated flue gases from a modern PC-powered plant would be typically 20
50 ppm, reducing to 2
5 ppm after treatment.

NOx control during combustion During combustion, nitrogen from the air or the fuel can be oxidized to form NOx in parts of the combustion zone that are at high temperatures and in which oxygen is present above the stoichiometric requirement for combustion (i.e., a “fuel-lean” environment). Methods to reduce NOx emissions start with low-NOx burners, which are designed to produce large swirling or branched flames with reduced flame temperature. Some burner designs also internally mix recirculated combustion gas with the incoming air 1 fuel mixture to further reduce flame temperature, and a similar result can be achieved by recirculating flue gas into the burner or furnace. Air staging or two-stage combustion is also used to control NOx formation. The primary combustion zone is maintained in an oxygen-deficient state by mixing only 70%
90% of the stoichiometric requirement with the fuel at the burner. The remaining 10%
30% secondary or overfire air is injected above the burners in a lower-temperature combustion zone. Thus, oxygen-rich conditions can occur only at lower temperatures, limiting NOx formation. These primary measures can reduce NOx in the combustion gas from a typical 300 ppm for conventional coal combustion to less than 100 ppm.

NOx removal by selective reduction The most common method to further reduce NOx in flue gas is selective catalytic reduction (SCR), in which ammonia or urea (NH2CONH2) is injected into the flue gas stream over a catalyst. The NOx is catalytically reduced to form nitrogen and water, the primary reactions being: NH2 CONH2 1 H2 O ! 2NH3 1 CO2

(3.28)

4NH3 1 2NO2 1 O2 ! 3N2 1 6H2 O

(3.29)

4NH3 1 4NO 1 O2 ! 4N2 1 6H2 O

(3.30)

2NH3 1 NO2 1 NO ! 2N2 1 3H2 O

(3.31)

The most common catalysts are oxides of vanadium and tungsten, configured in a ceramic-supported flat plate or honeycomb structure. Titanium and iron oxides, activated carbon, and zeolite catalysts are also used, depending on the proportions of NO and NO2 present. The optimal temperature for the catalyzed reaction is in the range of 300
400 C, and removal efficiencies of 90%
95% can be achieved. Selective reduction can also proceed without a catalyst, at temperatures in the range of 900
1100 C. However, this selective non-catalytic reduction (SNCR) process can achieve NOx removal performance comparable to SCR only if reagent mixing and distribution within the

Power generation fundamentals

63

reaction zone are carefully controlled to match the temperature profile. This is problematic under varying load conditions, particularly since feedback control from flue gas NOx levels, which provides efficient control for SCR, is ineffective with SNCR due to the complexity of the reagent injection system. The typical NOx removal efficiency for SNCR in practice is in the range of 30%
50%. Where this is sufficient to meet emissions standards, removal of catalyst costs gives SNCR an economic advantage over SCR.

Electron beam flue gas NOx removal As for FGD, electron beam flue gas treatment can also be used to remove NOx. In reactions similar to Equations (3.24)
(3.26), NO is either reduced to and released as nitrogen or oxidized to NO2. NO2 is converted to HNO3 (c.f., Equation (3.24)) and reacted with ammonia to produce ammonium nitrate: HNO3 1 NH3 ! NH4 NO3

(3.32)

which is collected and sold as a fertilizer. NOx removal efficiency of up to 70% was achieved using electron beam treatment in the EPS Pomorzany installation described earlier.

3.2.6 Thermal efficiency of conventional power plants The boiler efficiency of modern pulverized fuel, hard coal-fired units is 94%
95% (LHV basis), reducing slightly to 90%
91% for lignite-fired units due to the higher moisture content. When combined with the other elements of the Rankine cycle, the overall efficiency currently achievable in conventional plants is in the 40%
45% range. SC plants are more efficient and also sustain a higher efficiency under reduced load conditions. Table 3.8 illustrates the typical effect of turndown on plant efficiency for subcritical and SC units.

3.3

Combined cycle power generation

As discussed earlier, the thermal efficiency of a Carnot cycle, and of other practical thermodynamic cycles, is increased if the ratio TH/TC is increased. A combined cycle plant combines two or more thermodynamic cycles to exploit a wider Table 3.8 Power plant thermal efficiency penalty under part load conditions

Supercritical Subcritical

ηth (%) 100% load

ηth (%) 75% load

ηth (%) 50% load

45 39

43 35

37
39 28
29

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Carbon Capture and Storage

temperature range and reach a higher thermal efficiency than would be possible with a single cycle. This is achieved by using the relatively high-temperature reject heat from the first cycle to drive a second cycle, effectively reducing the overall TC. The concept can be simply illustrated in terms of two ideal Carnot cycles, as shown in Figure 3.15. In power-generation applications, the most common combined cycle plant comprises two stages: 1. A gas turbine operating a Brayton cycle (Section 3.1.6), fired either by natural gas or integrated with a gasification plant, followed by 2. A steam turbine operating a Rankine cycle (Section 3.1.5), driven by a heat-recovery steam generator (HRSG) that recovers heat from the high-temperature exhaust gases exiting the gas turbine.

A plant operating the Brayton cycle alone, with exhaust heat released to the atmosphere, is referred to as an open-cycle gas turbine (OCGT). A natural gas-fired combined cycle power plant is illustrated schematically in Figure 3.16. In the firstgeneration cycle, natural gas is burned in a combustion turbine which directly drives an electrical generator. Combustion temperatures are typically in the range

Temperature

TH

TI

TC

A

B Top cycle — ABCD (e.g., Brayton gas turbine cycle)

D

C

Heat transfer (HRSG) Bottom cycle — DCFE (e.g., Rankine steam cycle)

F

E

Entropy

Figure 3.15 Combined cycle concept based on ideal Carnot cycles.

OCGT plant Natural gas

Combuster

Electric

Compressor Air

Steam turbine Generator

Gas turbine

Electric Generator

power

power

Fuel gas

Heat-recovery steam generator

Cooling water Condenser

Figure 3.16 Process schematic of a natural gas
fired combined cycle power plant.

Power generation fundamentals

65

of 1000
1400 C, depending on the fuel, while final exhaust exit temperatures following additional turbine stages are in the range of 450
650 C. The steam cycle operates on similar principles to a normal fossil fuel
fired power plant, with the boiler replaced by a HRSG. Other combined cycle variants use pressurized fluidized bed combustion (PFBC) in a number of configurations: G

G

G

High-pressure PFBC combustion gas is used to drive a gas turbine. Natural gas plus PFBC combustion gas is used to co-fire a combustion turbine. Fuel is gasified in a PFBC and syngas is used to fire a gas turbine in a gasification fluidized-bed combined cycle.

In each case, steam is raised in the FBC, and additional heat may also be recovered from gas turbine exhaust.

3.3.1 Heat recovery steam generation The HRSG recovers heat from the gas turbine exhaust to generate steam at temperatures up to B650 C and pressures of 13
20 MPa. Although SC systems have been developed, heat-recovery steam generation is most commonly applied under subcritical conditions. The components of the HRSG—evaporator, superheater, and economizer—are functionally equivalent to those in a conventional steam boiler. Figure 3.17 illustrates schematically the heat transfer in the three sections of a simple HRSG, with exhaust gases moving from left to right and feedwater/steam from right to left. Feedwater entering the economizer is heated by the gas exiting the HRSG to a temperature close to the saturation temperature of steam at the operating pressure of the unit. The so-called approach temperature (ΔTA) is the difference between the temperature of water leaving the economizer and the saturation temperature and is kept at 10 C or more to prevent steam formation in the economizer. The flue gas

Temperature

Flue gas

Steam to turbine

Superheat temperature Stack temperature

Pinch point temperature Saturation temperature Economizer outlet temperature

Approach temperature

Flue gas

Feed water Superheater

Figure 3.17 Heat transfer in HRSG.

Evaporator

Economizer

66

Carbon Capture and Storage

HP steam

LP steam Attemperator

A

B

C

D

Flue gas IP reheat

Attemperator IP cold reheat

E

Selective Catalytic Reduction

A) HP Superheater B) IP Reheater C) HP Evaporator D) HP Economizer E) LP Evaporator F) LP Economizer

Deaerator

F

Flue gas to stack

LP feed HP feed

Figure 3.18 Process schematic for triple-pressure HRSG.

exit temperature from the HRSG is held above 100 C if it is necessary to prevent condensation, although lower temperatures are commonly used with suitable materials in order to maximize heat recovery. In the evaporator section, flue gas is cooled to close to the saturation temperature, providing the latent heat of evaporation to the hot water exiting the economizer. Heat recovery is maximized if the gas exiting the evaporator section is at the saturation temperature (i.e., the pinch point temperature—ΔTP—is zero). In practice this requires very large heat-exchange surfaces, leading to increased capital costs, and in practice a ΔTP of 10
20 C is typical. After evaporation, steam is superheated to close to the flue gas entry temperature. Additional burners (duct firing) may be included to increase the gas temperature and steam production capacity of an HRSG to meet peak demand, although this is not generally used to increase the baseload capacity in view of the relatively low efficiency of this supplemental firing. More advanced multipressure HRSGs improve overall thermal efficiency and achieve higher work output by including two or three parallel steam flows to drive HP, IP, and LP stages of the steam turbine, although this comes at the cost of a more complex plant. Figure 3.18 illustrates a state-of-the-art triple-pressure HRSG, with multistage economizers for the IP and HP flows. The key operating parameters of this HRSG design are summarized in Table 3.9. Modifications to the standard subcritical systems to optimize performance in HRSG applications include replacement of the high-pressure steam drum by a thinwalled steam
water separator, allowing rapid start-up to match that of the gas turbine and therefore improving operational flexibility.

3.3.2 Combined cycle thermal efficiency Considering the ideal Carnot cycle, the theoretical maximum efficiency is given by: ηmax 5 1
TC =TH

(3.33)

Power generation fundamentals

67

Table 3.9 Process parameters for triple-pressure HRSG Subsystem

Parameter

Value

Gas turbine HP steam system

Exhaust temperature Live steam temperature Live steam pressure Live steam temperature Live steam pressure Live steam temperature Live steam pressure Pinch point temperature Outlet temperature

570 C 535 C 16.9 MPa 535 C 2.9 MPa 200 C 0.4 MPa 11 C 81 C

IP steam system LP steam system

Flue gas

where for a combined cycle power plant the hot source corresponds to the combustion gas entering the turbine, with TH typically 1000
1400 C (1270
1670K), and the cold sink is the cooling medium of the Rankine cycle condenser, with TC typically 10
25 C (280
300K), depending on the plant location. These values yield theoretical maximum efficiencies in the range of 75%
85%. In practice, the thermal efficiency of a combined cycle power plant is given by: ηth 5 Net power output of the plant=Heating value of the fuel

(3.34)

and can be expressed either in LHV or HHV terms. Efficiencies achievable with current (2017) open-cycle and combined-cycle gas turbine plant are in the range of 35%
42% and 52%
60%, respectively (LHV basis), which are still significantly lower than ηmax, largely due to low-grade heat loss. If low-grade heat is fully used down to the cold sink temperature, for example, in a CHP plant, the overall energy utilization efficiency can approach the Carnot cycle efficiency. Efforts to increase efficiency also focus on increasing TH, in this case the temperature of the combustion gases entering the turbine, from the current maximum of about 1600 C toward 1700 C, and on alternative high-efficiency bottoming cycles, for example, using SC CO2 as the working fluid.

3.3.3 Integrated gasification combined cycle power generation In integrated gasification combined cycle (IGCC) power-generation, the fuel for the combined cycle plant is syngas, generated from a gasification system. This approach, which was first demonstrated in 1984 at Southern California Edison’s 100 MWe Cool Water coal gasification plant, results in a system with high efficiency, flexibility to use a wide range of feedstocks (including biomass and waste), and low or potentially zero carbon emissions. Figure 3.19 illustrates a simplified process scheme for an IGCC power plant, at the heart of which is the gasification process. This operates, as discussed in Section 3.1, by partial oxidation and steam reaction of carbon in the fuel to produce a syngas of CO and H2, which is combusted in the gas turbine.

68

Carbon Capture and Storage

Air

Air separation Feed from Brayton cycle O2 compressor

Steam

N2

Rankine cycle Steam turbine

N2

Coal milling and drying

Boiler feed water

Gasifier

Coal

Syngas cooler

Particulate removal

Generator Feed water

Fly ash Heat recovery steam generator

Flue gas desulfurization

Exhaust

N2

Sulfur

(NOx control)

Combustor Clean syngas

Brayton cycle Slag

Air

Compressor

Gas turbine

Generator

Figure 3.19 Simplified IGCC power plant process scheme.

Although the gasifier can be either air- or oxygen-blown, the latter system avoids syngas dilution with nitrogen, resulting in a product with typically double the heating value when compared to an air-blown system. Gasifier and turbine operability and carbon conversion efficiency also improve with oxygen-blown gasification. Cryogenic air separation (see Chapter 9) has been the technology most commonly used to date to produce oxygen for gasification, although a number of other technologies are also under development, including membrane systems (Chapter 8) and chemical looping gasification. The integration of steam use between the gasification plant and the HRSG is a key element in the efficiency of IGCC. Equally important is the relative ease with which pre-combustion carbon capture can be integrated into the IGCC scheme, as discussed in the next chapter.

3.4

Future developments in power generation technology

Since steam temperature is the fundamental determinant of thermal efficiency in a Rankine cycle, the development of materials capable of operating at ever higher temperatures is the main focus of RD&D work aiming to achieve higher efficiencies in conventional generation plants. In addition, novel approaches to power generation are under investigation with the aim of achieving high efficiency with integrated carbon capture.

Power generation fundamentals

69

48

Thermal efficiency (%LHV)

Ni–Cr Alloys (e.g., Inconel, HR6W) 35 MPa/700/720°C Austensitic (e.g., NF709) 31.5 MPa/620/620°C

46

Ferritic–Martensitic (e.g., NF616, P92) 30 MPa/600/620°C Martensitic steels (e.g., P91) 27 MPa/585/600°C

44

42

Ferritic steels (e.g., F12/X20) 25 MPa/540/560°C Ferritic steels (e.g., F12/X20) 17 MPa/538/538°C

40 Increasing steam conditions and steel performance requirements

Figure 3.20 Development of steels and superalloys for SC and USC boilers.

3.4.1 Materials development for SC and USC boilers The progressive development of steels for more advanced steam conditions and the resulting trend in plant efficiency is illustrated in Figure 3.20. A key design parameter in assessing material suitability is the creep rupture stress that can be maintained for the life of the plant. Creep strength is commonly assessed for a period of 105 h (about 11 years) at the operating temperature of the component, with an ability to withstand a pressure of 100 MPa being a typical requirement. Table 3.10 summarizes the characteristics of a number of advanced steels and superalloys that have been developed to address the challenge of SC and USC operation. Advances in welding processes have also been made in order to ensure tight control of the weld deposit composition, as well as pre- and post-weld heat treatment, which are important to ensure long life at high temperatures and pressures. RD&D work with the aim of raising steam temperature to 700 C or above has progressed under the European Union
funded Thermie AD700 project (now part of the VGB Emax Power Plant Initiative), targeting 700 C, and the US Department of Energy funded advanced USC project, targeting 760 C. As part of these projects nickel
chromium superalloys (such as Haynes 282, NF709, HR6W, and Inconel 740H) are being developed for the fabrication of boiler and gas turbine components exposed to the highest temperatures, while high-strength 9
12Cr martensitic steels are being further developed for components operating at temperatures up to 650 C. In early 2015, Alstom completed pilot testing of a steam loop at 760 C in the Barry PC power plant at Mobile, AL, and full-scale demonstration of A-USC is anticipated before 2020.

70

Carbon Capture and Storage

Table 3.10 Steel and superalloys developed for high-temperature service Designation Composition P91

NF616

NF12

NF709

HR6W

Inconel

Description

9Cr
1Mo
Nb
V

High-strength martensitic steel used for operating temperatures up to 600 C and pressures to 27 MPa 9Cr
0.5Mo
1.8W
V
Nb A ferritic
martensitic steel developed for use in boiler tube and pipework to overcome high expansion of austenitic alloys 12Cr
2.6W
2.5Co
0.5Ni
V
Nb Developed by Nippon Steel with the design aim of achieving a 30% improvement in creep rupture strength compared to NF616 (P92) steel 20Cr
25Ni A novel austenitic steel alloy suited to high temperatures due to low creep and high corrosion resistance 23Cr
45Ni
6W
Nb
Ti
B A high Ni
Cr superalloy developed for 700 C service; high creep rupture strength due to the strengthening effect of W and Nb 50
70Ni, 15
25Cr, 3
10Mo, A Ni
Cr superalloy with less than 3
6Nb 10% Fe

For USC service, the HP sections of steam turbines generally use a triple-shell construction to distribute the thermal and burst stresses. Similar to boiler service, nickel superalloys are required for turbine components operating at the highest temperatures and pressure (HP nozzles and rotors), while advanced high-strength austenitic steels are used for the second line of temperatures, and with inner and outer shells of progressively lower alloy steels. As noted earlier, reducing the flue gas exit temperature to below the dew point is desirable to maximize boiler efficiency but runs the risk of acid corrosion to heat exchangers and ducting due to condensation of water and the formation of sulfuric acid. The use of plastic, glass fiber, and Teflon materials for these cold end surfaces can allow exit temperatures to be reduced to below 100 C, leading to an increase in overall cycle efficiency. In early 2009, Foster Wheeler commissioned the world’s first SC CFB boiler, the Lagisza 460 MWe unit at the Poludniowy Koncern Energetyczny SA (PKE) plant in Poland. This unit has a plastic heat exchanger as the final heat-recovery stage, cooling flue gas to 82 C.

Power generation fundamentals

3.5

71

References and resources

3.5.1 References Breeze, P., 2014. Power Generation Technologies. Newnes/Elsevier, Oxford, UK. Cheremisinoff, N.P., 2012. Clean electricity through advanced coal technologies, Handbook of Pollution Prevention and Cleaner Production, vol. 4. Elsevier, Oxford, UK. Department of Trade and Industry, 1999. Cleaner Coal Technologies. DTI, UK. Available at www.berr.gov.uk/files/file22078.pdf. Drbal, L., Westra, K., Boston, P. (Eds.), 1996. Power Plant Engineering. Springer Science 1 Business Media, New York. IEA, 2007. Fossil Fuel-Fired Power Generation; Case Studies of Recently Constructed Coaland Gas-Fired Power Plants. OECD Publishing, Paris, France. Pansini, A.J., Smalling, K.D., 2006. Guide to Electric Power Generation. The Fairmount Press, Lilburn, GA. Rao, A.D. (Ed.), 2012. Combined Cycle Systems for Near Zero Emission Power Generation. Woodhead Publishing Ltd, Cambridge, UK. Stiegel, G.J., Ramezan, M., 2006. Hydrogen from coal gasification: an economical pathway to a sustainable energy future. Int. J. Coal Geol. 65, 173
190.

3.5.2 Resources Clean-energy.uc (news and information about coal gasification): www.cleanenergy.us/index. phpwww.clean-energy.us/index.php. Clean Coal Today (National Energy Technology Laboratory quarterly newsletter): www.netl. doe.gov/technologies/coalpower/cctc/newsletter/newsletter.html. Cooperative Research Centre for Coal in Sustainable Development (CCSD), Power Station Emissions Handbook: www.ccsd.biz/PSE_Handbook. Ecofys; International comparison of fossil power efficiency and CO2 intensity—Update 2014: www.ecofys.com/files/files/ecofys-2014-international-comparison-fossil-powerefficiency.pdf. Future of Coal (MIT interdisciplinary study): http://web.mit.edu/coal. Gasification Technologies Council: www.gasification.org. Heat recovery steam generator design: www.hrsgdesign.com. IEA Clean Coal Centre: www.iea-coal.org.uk/site/ieacoal/home. IEA Clean Coal Centre (clean coal technologies database): www.iea-coal.org.uk/site/ieacoal/ databases/clean-coal-technologies. Phyllis (database of biomass and waste composition): www.ecn.nl/Phyllis. University of Utah, Utah Clean Coal Program: www.uc3.utah.edu. US Department of Energy National Energy Technology Laboratory, RD&D in coal and power systems: www.netl.doe.gov/technologies/coalpower. US Department of Energy Vision 21 project: www.fossil.energy.gov/programs/powersystems/ vision21. VGB Emax (formerly the Thermie AD700 project): www.vgb.org/en/emax.html.

Carbon capture from power generation 4.1

4

Introduction

The fundamental chemical process involved in the generation of power from carbon-based fuel is the exothermic oxidation of carbon, as described in Section 3.1, and since CO2 is the lowest-energy end-point of the oxidative reaction chain, its production is unavoidable. The elimination of carbon from power plant emissions therefore requires either: G

G

G

Decarbonation of the fuel prior to combustion (pre-combustion capture) Separation of CO2 from the products of combustion (post-combustion capture) Reengineering the combustion process to produce CO2 as a pure combustion product, obviating the need for its separation (oxyfuel or chemical looping combustion)

These approaches are illustrated schematically in Figure 4.1. As shown in the figure, the pre- and post-combustion approaches both require technologies to separate CO2 from a gas mixture comprising CO2 1 H2 or CO2 1 N2, respectively. For oxyfueling, the oxygen supply can be achieved either through a separation of O2 from air (O2 1 N2 1 trace gases) or by the delivery of oxygen to the combustion process in the form of a solid oxide (chemical looping). Some advantages and disadvantages of these capture options are summarized in Table 4.1. Several fundamental technology areas are in use or under development to address these gas separation challenges, including absorption, adsorption, hydratebased separation, membranes, chemical looping. and cryogenic separation systems. The application of these technologies to pre- and post-combustion capture and to oxyfuel/chemical looping combustion is outlined in the following sections, and the technologies are described in detail in Chapters 6
9.

4.2

Pre-combustion capture

Pre-combustion capture involves decarbonation by gasification of the primary fuel, commonly coal or biomass, to produce hydrogen through a combination of partial combustion, reforming and water
gas shifting (WGS) (Section 3.1), and the separation of CO2 from the resulting reaction product stream. The current development and demonstration focus of pre-combustion capture is on IGCC plants, using the process shown schematically in Figure 4.2, although in principle the approach is equally applicable to all integrated gasification systems

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00004-0 © 2017 Elsevier Inc. All rights reserved.

76

Carbon Capture and Storage

N2

Post-combustion capture

Fuel Power and heat Air

CO2 Separation

CO2

Pre-combustion capture

Fuel

Gasification and reforming

CO2

CO2 Separation

Air, O2, Steam

H2

Power and heat

N2

Air Oxyfuel combustion

CO2

Fuel

Power and heat

O2 Air

N2

Air separation Chemical looping combustion

Fuel

CO2

Metal oxide reduction

Me

Power and heat MeO

N2

Metal oxidation

Air

Figure 4.1 Options for CO2 capture from power generation. Table 4.1 Advantages and disadvantages of capture options Capture option

Advantages

Disadvantages

Pre-combustion

Lower energy requirements for CO2 capture and compression; fully developed technology, commercially deployed at the required scale in other industries Fully developed technology, commercially deployed at the required scale in other industries Opportunity for retrofit to existing plant Mature air separation technologies available; very high [CO2] simplifies capture process Very high [CO2] simplifies capture process

Temperature and efficiency issues associated with hydrogen-rich gas turbine fuel

Post-combustion

Oxyfuel combustion

Chemical looping combustion

High parasitic power requirement for solvent regeneration; low [CO2] impacts capture efficiency High capital and operating costs for current absorption systems Costly and energy intensive air separation step; significant plant impact makes retrofit unattractive Immature technology, currently under development

Carbon capture from power generation

Air

Air separation

77

N2, Air

Combined cycle plant H2

O2 Coal

Gasification

Electric power

H2 CO CO2

WG shift

H2 CO2

Cleanup

Capture CO2

Steam

Sulfur

Compression

CO2 to transportation and storage

Figure 4.2 Pre-combustion capture IGCC process schematic. Table 4.2 CO2:H2 separation technologies for pre-combustion capture Technology area Currently developed technologies

Example technologies under development

Absorption-based separation (Chapter 6)

Novel solvents to improve performance; improved design of processes and equipment

Physical solvents (e.g., Selexol, Fluor processes), chemical solvents

Adsorption-based separation (Chapter 7) Chemical looping systems (Chapter 7) Membrane separation (Chapter 8) CO2 liquefaction Cryogenic separation (Chapter 9)

Sorption-enhanced water
gas shift (SEWGS) process; elevated temperature pressure swing adsorption Chemical looping combustion or reforming Metal and ceramic membrane WGS reactors; ion transport membranes Hybrid cryogenic 1 membrane processes

where hydrogen is the final syngas product, such as integrated gasification fuel cell systems (see Section 4.7). The separation of CO2 and H2 can be achieved using a number of technologies, as shown in Table 4.2, of which the use of physical solvents (such as the Selexol and Fluor processes, described in Section 6.2) is currently the most commercially developed. In this and similar tables below, underlined technologies are those that are currently deployed or close to being deployed in CCS projects. As well as the relatively higher CO2 concentration ([CO2]) in the gas stream (.20% in the H2 1 CO2 stream vs 5%
15% in a post-combustion flue gas stream), CO2:H2

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Carbon Capture and Storage

separation is somewhat easier than the post-combustion separation of CO2 and N2 due to the greater difference in molecular weights and molecular kinetic diameters for CO2 versus H2 than for CO2 versus N2. In addition to the further development of technologies related to CO2:H2 separation (i.e., advanced solvents, sorbents, and membranes), other aspects of precombustion capture processes that are being addressed by RD&D efforts include: G

G

G

G

Optimization of gasification process to use less steam (catalysts, flow configurations, and heat integration) Development of H2-fueled gas turbines (addressing combustion processes, including flameless combustion, burner design, heat transfer and cooling, materials impact, and operational aspects) Physical, energetic, and operational integration of pre-combustion capture process into an IGCC plant Integration of gasification with CO2 capture

4.2.1 Pre-combustion RD&D projects The European Union
funded European Technology Platform for Zero Emission Fossil Fuel Power Plants (ETP ZEP) exemplifies RD&D activity in the area of precombustion capture and was established in 2005 with the initial aim of enabling the commercial deployment of fossil-fuel power plants with zero CO2 emissions by 2012. This ambitious goal was subsequently reset to a 2020 timeframe for demonstration of commercial viability, and the remit extended to support rapid large-scale deployment post-2020.

R&D and pilot-scale testing A number of projects were initiated from 2004 onward to address some of the key technologies required to enable pre-combustion capture from IGCC plants, as summarized in Table 4.3. Much of the R&D focus for pre-combustion capture has been on the WGS reaction, because this is the area where the main energy penalty is incurred, due to the amount of steam used for the WGS reaction and the limited recovery of heat produced in the conversion. Current R&D topics include minimizing the heat loss and/ or the amount of steam used in the WGS, for example, by developing new shift catalysts which operate with less steam, alternative configurations of the WGS, and combining the WGS reaction with CO2 adsorption to separate CO2 within the WGS reactor. The ENCAP project concluded in 2007 that the technologies for ZEIGCC could be considered largely ready for full-scale demonstration, exceptions being the need for further design optimization and testing of burners for H2-rich combustion, and the optimization of turbine blade material for higher turbine inlet temperatures. Following a technology selection decision in 2007, the project planned to focus further work on the 30 MWth Oxyfuel pilot then under construction by Vattenfall at Schwarze Pumpe Power Plant site, Germany (see Section 4.4).

Carbon capture from power generation

79

Table 4.3 EU R&D projects addressing IGCC pre-combustion capture Project

R&D objectives

ENCAP (SP2) (leading partner, Vattenfall AB) 2004
7

Optimization of CO-shift conversion Modeling of H2-rich combustion and experimental validation Development and testing of burners for H2-rich combustion in gas turbines Hydrogen compatibility of turbine components Development of pre-combustion capture plant specifications Review of IGCC operational experience, focusing on operational problems, corrosion and plugging, and plant integration Analysis of further optimization potential Identification of technology development requirements for gasification and syngas cleaning Feasibility study for optimized zero-emission IGCC (ZEIGCC) Further development of the SEWGS following on from the CACHET (FP6) project Reduce energy penalty and cost per tonne of CO2 avoided through Optimization of sorbent materials Reactor and process design optimization Smart integration of SEWGS unit in an IGCC power plant Identification and development of new techniques for pre-combustion capture Development of advanced oxygen production technologies Further develop the key enabling technologies advanced in earlier (FP6) projects

COORIVA (leading partner, TU Frieberg)

CAESAR (FP7) (leading partner ECN) 2008
12

DECARBIT (leading partner SINTEF) 2008
12

The CAESAR project developed a proprietary hydrotalcite-based sorbent (ALKASORB1) with a substantially lower energy penalty when compared to Selexol and achieved its target cost of CO2 avoided below h25/t-CO2. A 35 t-CO2/ day pilot-scale follow-up (EU Horizon 2020 funded STEPWISE project; 2015
19) will apply the technology to CO2 removal from blast-furnace gases as the next step toward a full-scale SEWGS demonstration plant in 2020
2022. The world’s first pilot-scale testing of pre-combustion capture started operations in 2010 at the ELCOGAS 335 MWe IGCC at Puertollano, Spain, with 100 t-CO2/ day separated from a 3600 Nm3/h (B2%, 14 MWth) syngas slipstream using amine absorption. A slightly smaller scale pilot, using the Selexol process to capture 1.4 t-CO2/h from a 0.8% syngas slipstream (equivalent to 5 MWth), was conducted

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from 2011 to 2013 and the Nuon/Vattenfall IGCC plant at Buggenum in the Netherlands, with the objective of demonstrating and optimizing pre-combustion capture before full-scale deployment at the 1.3 GW Magnum CCGT plant at Eemshaven in the Netherlands (see below). The main efficiency loss associated with pre-combustion capture occurs in the WGS section, due mainly to the amount of steam used for the WGS reaction and the limited recovery of heat produced in the conversion. Current R&D focus for pre-combustion capture is on minimizing the amount of steam use in the WGS, for example, by developing new shift catalysts which operate with less steam, alternative configurations of the WGS, and combining the WGS reaction with CO2 adsorption.

Demonstration and early deployment projects Building on the ENCAP and COORIVA R&D results, the German energy company RWE Power has planned to construct an IGCC plant with CCS at its Goldenbergwerk site near Cologne in Germany. The gasification plant would be lignite-fueled, with a gross electrical output of 450 MWe, reducing to 360 MWe net after deducting the plant and CCS power utilization, and was initially expected to be commissioned at the end of 2014. A capture efficiency of 90% was targeted, and storage of the 300 t-CO2/h (2.6 Mt-CO2/year) captured in the plant was planned to be in a saline aquifer or depleted gas reservoir, with evaluation of potential storage sites expected to be completed in 2010. Figure 4.3 shows the overall project plan as laid out in 2008. A major risk recognized at project inception was the lack of an EU-wide legal and regulatory framework for CO2 transport and storage; because of this the Goldenbergwerk plant included an option to run without capture, and the project was put on hold in 2010 awaiting passage of the German Carbon Storage Law, which was required to enable storage site selection. Several other demonstration and commercial-scale pre-combustion capture projects have also been announced with the expectation of being operational by 2020, as shown in Table 4.4, and up-to-date project information can be found in the project databases listed under Resources in Chapter 2. The “on hold” status of many announced demonstration projects highlights some of the non-technical challenges faced by power plant operators and their partner organizations in pursuing CCS; nevertheless many new IGCC and CCGT plants are being commissioned “capture-ready,” examples being Duke Energy’s Edwardsport and TECO’s Polk IGCCs in the United States, and the Vattenfall/Nuon Magnum CCGT in the Netherlands.

4.3

Post-combustion capture

In post-combustion capture, CO2 is removed from the combustion reaction product steam—the flue gases—before emission to the atmosphere. Post-combustion

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Research and development projects ENCAP COORIVA Demonstration stage projects Power plant project Project development Engineering and approvals Construction and commissioning Plant start-up and operation CO2 transport and storage project Storage site screening and appraisal Exploration drilling at selected site Storage project approvals Construction and commissioning Pipeline planning and approvals Pipeline construction and tie-in Transport and storage operation

Figure 4.3 RWE pre-combustion capture demonstration plant project plan.

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Table 4.4 Pre-combustion capture demonstration and early deployment projects Project; operator and Project description partners

Planned (actual) start-up

Edwardsport IGCC; Duke Energy, USA

618 MW IGCC with capture planned 2012 (2013, plant CCS ready using physical absorption process but on hold due to storage site unsuitability) Kemper County IGCC; 582 MW lignite-fueled IGCC with 2016 3.5 Mt-CO2/year for EOR Mississippi Power, USA Coal-fired IGCC with 2 Mt-CO2/year 2016 (Stage II) Huaneng GreenGen; 2020 (Stage III) for onshore EOR; Stage II at Peabody Energy, 100 MW scale, Stage III at China 400 MW 175 MW coal-fired IGCC with Quintanna, Great 2018 2.1 Mt-CO2/year for onshore EOR Northern Power Development, USA Dongguan Taiyangzhou 800 MW coal-fired IGCC with 1 Mt- 2019 Power Corp., China CO2/year for EOR or storage in depleted gas reservoir Nuon Magnum; 1.2 GW multifuel plant (coal, 2020 Vattenfall/Nuon, Shell biomass, gas fired) with CO2 storage in North Sea oil and gas fields

capture is thus an extension of the flue gas treatment for NOx and SOx removal, made more challenging by the relatively higher quantities of CO2 in the gas stream (typically 5%
15%, depending on the fuel being used). A similarly wide range of technologies is available or under development to address the post-combustion CO2:N2 separation problem, as shown in Table 4.5. The use of chemical solvents, such as MEA (described in Section 6.1), is the most mature and is widely deployed for natural gas treatment, although many of the currently planned demonstration projects are expected to use the chilled ammonia process (CAP; Section 6.2.1). As well as technologies to address the gas separation challenge, several other aspects of the post-combustion process are also the focus of ongoing RD&D, notably: G

G

G

Integration and optimization of the post-combustion process within the power plant Environmental impact (including see Section 2.3) of the overall post-combustion capture process and specific solvent use Procedures for optimal post-combustion process operation under varying plant conditions

An alternative post-combustion capture approach that has been proposed is to use cooled, CO2-rich flue gases to feed bioreactors producing microalgal biomass

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Table 4.5 CO2:N2 separation technologies for post-combustion capture Technology area

Currently developed technologies

Example technologies under development

Absorption-based separation (Chapter 6) Adsorption-based separation (Chapter 7) Membrane separation (Chapter 8) Cryogenic separation (Chapter 9)

Chemical solvents (e.g., MEA, chilled ammonia) Zeolite and activated carbon molecular sieves

Novel solvents to improve performance (e.g., phase change solvents); improved design of processes and equipment Carbonate sorbents; calcium/chemical looping

Polymeric membranes

Immobilized liquid membranes; molten carbonate membranes

CO2 liquefaction

Hybrid cryogenic
membrane and hydrate
membrane processes

that would be used as a biofuel, by either direct combustion or gasification with subsequent liquid fuel production (biodiesel). This is discussed together with other industrial use options in Chapter 22.

4.3.1 Post-combustion RD&D projects A number of post-combustion capture systems using monoethylene amine stripping (Section 6.2.1) have been in commercial operation since the late 1970s, providing CO2 for industrial use; examples are the IMC Global operated plant at Trona, CA, capturing 800 t-CO2/day for brine carbonation from a coal-fired boiler, and AES Power operated plants at Warrior Run, MD and Shady Point, OH, capturing 200
800 t-CO2/day from coal-fired power plant flue gas slipstreams for refrigeration and food processing. These installations provide pilot-scale proof of this absorption technology. However, these installations have not been used as pilots to investigate scale-up to capture the full plant emissions, due to the limited quantity of CO2 required for the specific end users served by each plant. In view of the relative maturity of amine stripping as a post-combustion capture option, substantial R&D effort has been and continues to be applied to further improve the performance of this technology, as the most likely pathway toward rapid commercial deployment of CCS. Recent improvements have been both evolutionary—for example, a gradual reduction in energy penalty through improved process design and integration—and revolutionary—the emergence of phase change

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solvents being a significant example. Progress across the wide range of postcombustion capture technologies, as listed in Table 4.5, is summarized below and discussed in more detail in the following chapters.

R&D and pilot-scale testing The objects of some recently completed and ongoing international R&D projects investigating post-combustion capture are shown in Table 4.6. The European Union has funded a series of R&D projects, under the EC’s Sixth and Seventh Framework Programs (FP6/7) and the Research Fund for Coal and Steel (RFCS), beginning with the CASTOR project, which included among its aims the development of new sorbents for post-combustion capture with an energy consumption target of , 2 GJ/t-CO2 at 90% recovery efficiency and a cost of h20
30/t-CO2 avoided. The project scope included completion of pilot-plant testing to demonstrate reliable and efficient operation of post-combustion capture. The pilot plant was constructed and commissioned during 2005 and started operation in Table 4.6 EU R&D projects addressing post-combustion capture Project

R&D objectives

CASTOR (FP6) 2003
8 CESAR (FP7) 2008
11

Novel solvents to reduce energy penalty

CAOLING (FP7) 2009
12 CAL-MOD (RFCS) 2010
13 iCAP (FP7)2010
13

OCTAVIUS (FP7) 2012
17 HiPerCap (FP7) 2014
17

Novel (e.g., hybrid) solvent systems, building on CASTOR results High flux membranes contactors as an alternative to packed columns Improved modeling and integration studies at system and plant level Pilot testing validation of new solvents and plant performance Scale-up of CaO looping capture to 1 MW scale Supported by lab-scale studies on sorbent properties Development of simulation tools to support industrial-scale demonstration and deployment of calcium looping capture, including sorption kinetics, sorbent attrition, and regeneration Pilot testing of multiphase post-combustion solvent system Investigation of capture based on CO2 hydrate formation Development of thermodynamic models for multiphase solvents Membrane development for pre- and post-combustion applications Building on CASTOR and CESAR results Pilot test the DMXt process Build on CESAR results and reduce efficiency penalty by 25% Process design improvement to reduce capital and operating costs Identify, assess, and select two most promising new or emerging technologies to achieve a step change in capture performance Establish a technology roadmap for further development of the two selected new capture processes

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early 2006 at the 400 MWe pulverized bituminous coal-fired Esbjerg power station, operated by Danish energy company DONG Energy. The pilot plant captured 90% of the CO2 from a 5000 Nm3/h, 0.5% flue gas slipstream taken after wet FGD, yielding 1 t-CO2/h. A number of solvents were pilot-tested in 1000 hour tests, including 30 wt% MEA and two proprietary solvents, CASTOR-1 and CASTOR-2. The pilot testing validated the post-combustion capture process and resulted in energy consumption of 3.5 GJ/t-CO2 for the CASTOR-2 solvent, with the potential to reduce this to 3.2 GJ/t-CO2 with further plant heat integration, and indicated capture costs in the range of h35
37/t-CO2 avoided. Reduced solvent degradation and corrosivity were further benefits of the two CASTOR solvents when compared to MEA. Following on from the successful CASTOR results, 2000 hour tests were conducted during 2009
2010 at the Esbjerg pilot plant on the novel CESAR solvents but, recognizing the difficulty in achieving a step change in energy consumption from incremental solvent improvements alone, subsequent projects, including iCAP and HiPerCap, sought to broaden the research toward achieving such a step change.

Demonstration and early deployment projects These research and pilot-scale programs have led to the announcement of a number of demonstration-scale post-combustion capture projects with start-up planned in the years to 2020, as shown in Table 4.7. A demonstration-scale test facility has also been established at Statoil’s Mongstad refinery in Bergen, Norway, following the construction and start-up in 2010 of a 280 MWe plus 350 MWth natural gas
fired CHP plant. The European Table 4.7 Post-combustion demonstration and early deployment projects Project; operator and partners

Project description

Planned (actual) start-up

Mountaineer; American Electric Power

20 MW demonstration plant, 110 kt-CO2/year capture using Alstom CAP and geological storage 160 MW coal-fired plant retrofit, Shell Cansolvt capture process, 1 Mt-CO2/year for EOR with excess to saline aquifer storage 240 MW slipstream from 610 MW coal-fired plant, KM-CDR amine capture, 1.6 Mt-CO2/year for EOR 385 MW gas-fired plant retrofit, amine capture, 1 Mt-CO2/year to depleted gas field storage

2009
2011

Boundary Dam; SaskPower

Petra Nova W.A. Parish; NRG Energy, JX Nippon Oil and Gas Exploration Peterhead/Goldeneye; Scottish and Southern Electric, Shell

2014

2016

2020— project on hold

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Carbon Capture and Storage

CO2 Test Centre Mongstad (TCM) provides a 100 kt-CO2/year capture facility with options for capture both from post-combustion flue gas and from refinery operations. A range of capture technologies have been tested at TCM, including amine, other solvents, and CAPs (Figure 4.4), and work at the center has included the development of verification protocols to enable performance comparison of different absorption processes (see Thimsen et al., 2014). Other partners in the TCM are Gassnova, Shell, and Sasol. The largest of these projects will bring the demonstration of post-combustion capture up to the full scale of commercial deployment.

4.4

Oxyfuel combustion

Oxyfuel combustion requires the delivery of oxygen rather than air to the combustion chamber, so that the gaseous combustion reaction product is near-pure CO2 rather than a mixture from which CO2 needs to be separated. Oxygen may be delivered either as a gas stream, produced by the separation of O2 from air (effectively an O2 1 N2 binary mixture), or as a solid oxide in a chemical looping process. Table 4.8 summarizes the technologies that can be applied to oxyfuel combustion. Combined cycle gas turbine emissions

3 to 4% CO2

Amine absorption plant

N2 CO2

Other refinery emissions

13% CO2

Chilled ammonia process

N2

Figure 4.4 European CO2 Test Centre Mongstad configuration.

Table 4.8 O2:N2 separation technologies for oxyfuel combustion capture Technology area

Currently developed technologies

Example technologies under development

Adsorption-based separation (Chapter 7) Membrane separation (Chapter 8) Cryogenic separation (Chapter 9)

Zeolite and activated carbon molecular sieves Polymeric membranes

Perovskites and chemical looping technology Ion transport membranes; carbon molecular sieves Improvements in distillation processes

Distillation

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In addition to RD&D focused on improvements in air separation for oxygen supply, other aspects of the oxyfuel process that are the subject of current research include: G

G

G

G

Characteristics of oxyfuel combustion processes (heat transfer, ash properties and composition, fouling) for a variety of solid fuel types Impact on boiler and combustion system (e.g., fluidized bed) design, construction materials, and operation, including flexibility for air firing Optimization of existing flue-gas treatment technologies for specific oxyfuel conditions (CO2-rich flue gas stream) Optimization of air separation units (ASUs) to reduce energy requirement, improve efficiency, and optimize overall system integration

4.4.1 Oxyfuel RD&D projects In 2001 the Swedish power company Vattenfall AB, Europe’s third-largest power company, began a comprehensive RD&D program into oxyfuel combustion, which it had identified as the preferred option for lignite-fueled plants. Vattenfall generates . 40% of its power from fossil fuels, and the aim of the program is to develop oxyfuel technology for full commercial deployment by 2015 at a target capture cost of less than h20/t-CO2 avoided.

R&D and pilot-scale testing Between 2001 and 2007, five laboratory-scale test rigs were commissioned at universities in Sweden and Germany to investigate oxyfuel processes and performance, as summarized in Table 4.9. Following this laboratory-scale program, a 30 MW pilot plant was put into operation in September 2008 at the Schwarze Pumpe power plant in Germany as an intermediate step-up toward a full demonstration plant. This was the first oxyfuel pilot plant in the world, and the main objectives of the initial 3-year pilot program were: G

G

G

G

Validation of laboratory-scale results and engineering work for lignite and hard coal combustion Optimizing the integration of oxyfuel requirements into power plants Improving knowledge and gaining experience of oxyfuel combustion dynamics and operational issues Demonstration of capture technology and possible underground storage, pending suitable site identification and permitting

Planned demonstration projects Progressing from this lab- and pilot-scale program, a 250 MWe demonstration plant was envisaged as the final step-up before full commercial deployment. This was planned at the 3 GWe Ja¨nschwalde power plant in Germany, which consists of six 500 MWe generation blocks, each comprising two 650 MWth (250 MWe) conventional lignite-fired boilers driving a single steam turbine. It was planned to add one

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Table 4.9 Vattenfall AB-commissioned laboratory-scale test rigs for oxyfuel R&D Institute

Test rig

R&D objectives

Technical University of Hamburg-Hamburg, Germany Technical University of Dresden, Germany

20 kW combustion test rig with nonrecirculating oxyfuel combustion 50 kW recirculating oxyfuel test rig

Thermodynamics of oxyfuel process

Chalmers University of Technology, Gothenburg, Sweden

FGD operation on oxyfuel flue gas stream Combustor dynamics when shifting between oxygen and air firing Novel FGD processes 100 kW recirculating oxyfuel Oxyfuel combustion research test rig with wet and dry flue gas recirculation, assessing the changes in radiation and reaction kinetics under oxyfuel conditions 500 kW recirculating oxyfuel Drying and oxyfuel combustion test rig of lignite

Brandenburg Technical University (BTU), Germany Impact of recirculation Stuttgart University 20 kW combustion test rig conditions and staged Institute of Process with nonrecirculating combustion Engineering and Power oxyfuel combustion 500 kW recirculating oxyfuel Power plant system integration Plant Technology combustion test rig, with and combustion flame (IVD), Germany all power plant systems behavior

250 MWe oxyfuel boiler to one of the generation blocks, allowing demonstration of oxyfuel technology alongside conventional combustion. Feasibility studies began in the mid-2008, with construction planned to commence in 2011 and start-up scheduled for 2015. The overall RDD&D timeline was shown in Figure 1.11 and clearly illustrates the 20-year timescale required to bring these technologies to the stage of full commercial deployment. Unfortunately the Ja¨nschwalde demonstration was canceled in 2011. Fewer demonstration-scale and early deployment oxyfuel capture projects are being planned compared to pre- and post-combustion capture; a few that have been announced are summarized in Table 4.10.

4.5

Chemical looping systems

Chemical looping combustion is a form of oxyfueling in which oxygen is introduced to the combustion reactor via a metal oxide carrier (MexOy), which is either

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Table 4.10 Oxyfuel demonstration and early deployment projects Project; operator and partners

Project description

Korea CCS 2; KCRC

2018 500 MW coal-fired plant, with c. 2 Mt-CO2/year to saline aquifers or depleted gas fields 300 MW coal-fired plant, 2020 1 Mt-CO2/year for EOR in nearby fields

Daqing CCS; China Datang Corp. and Alstom White Rose; National Grid plc, Alstom UK Ltd.

Planned start-up

426 MW coal-fired plant, 2020, but project on hold due to 2 Mt-CO2/year to offshore saline cancellation of the UK CCS Demonstration competition aquifer or EOR storage

fully or partially reduced in the combustion reaction. The chemical looping concept is very flexible, and options have been demonstrated for full combustion, reforming to produce syngas, and for hydrogen production, either by reforming, WGS and CO2 removal, or indirectly during carrier regeneration. Chemical looping can also be applied to capture CO2, either in a postcombustion application or in gasification (pre-combustion) systems, where it can be used in combination with a chemical loop to provide oxygen to the gasifier.

4.5.1 Chemical looping combustion Considering methane as the fuel, chemical looping combustion proceeds according to the reaction: CH4ðgÞ 1 4Mex OyðsÞ ! 4Mex Oy
1ðsÞ 1 CO2ðgÞ 1 2H2 OðgÞ

(4.1)

This reaction can be applied either at high pressure in a gas turbine cycle or at atmospheric pressure in a steam cycle. After heat recovery from the off-gas, steam can be condensed out, leaving a high-purity CO2 stream for storage. Following this fuel oxidation step, the spent carrier is circulated out of the combustion reactor into a carrier reoxidation reactor and regenerated in the reaction: 4Mex Oy
1ðsÞ 1 2O2ðgÞ 24Mex OyðsÞ

(4.2)

This reoxidation captures oxygen directly from a supply of compressed air, eliminating the need for a separate ASU for oxygen supply. The overall chemical looping process is illustrated schematically in Figure 4.5. Oxides of the common transition metals (Fe, Cu, Ni, Mn, Ba) are possible carriers, with Fe2O3/Fe2O2, NiO/Ni, and BaO2/BaO being extensively studied. The fuel oxidation step may be exothermic (for Cu, Mn, or Ba carriers) or

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Fuel

CO2 H2O

Metal oxide reduction

Metal oxide

Metal Metal oxidation

Air

N2

Figure 4.5 Chemical looping combustion process.

Table 4.11 Chemical looping combustion using NiO carrier Process

Reaction

ΔH

Fuel oxidation

CH4 1 4NiO ! CO2 1 2H2 O 1 4Ni 1 Ni 1 O2 ! NiO 2

175 kJ/mol CH4

Regeneration

Fuel Metal oxide reduction

CO2 H2O Metal oxide

Metal

2489 kJ/mol O2

Cooling N2

Metal oxidation

CO2 H2O

Generator

Air Compression

Gas turbines

Figure 4.6 Chemical looping combustion applied in a gas turbine cycle.

endothermic (for Fe and Ni carriers), while the carrier reoxidation step is always exothermic, the total energy released in the overall process being the same as for the direct combustion of the fuel. Table 4.11 shows the reactions and energetics with NiO as the carrier. A schematic of chemical looping combustion applied in a gas turbine cycle is shown in Figure 4.6. The fuel oxidation reactor here replaces the conventional combustion chamber of the gas turbine, while the CO2 plus steam off-gas from the reoxidation reactor can also be expanded through a turbine to generate additional power. In development work to date, the metal oxide carrier is typically in the form of particles with a diameter of 100
500 μm, and in some cases (e.g., Ni) it is carried on an alumina support. The reactions take place in two fluidized bed reactors, which achieve efficient heat and mass transfer. The recycling of solid carrier between the two reactors is both an important control on the operating temperatures

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Table 4.12 Current RD&D areas in chemical looping combustion Research area

Description

Performance of mixed oxide Assessment of mixed carriers, such as Fe2O3
CuO, Ni
Ba, and Ni
La, with the aim of maximizing reactivity and carriers stability under cyclic operations. Adding a second metal can aid in the formation of easily reducible oxides of the primary carrier while improving carrier
support interaction in the case of supported oxides Chemical looping with Identification and evaluation of carriers which release oxygen oxygen uncoupling in the fuel reactor, allowing combustion in gaseous rather than bound oxygen Carrier material handling Development of systems for high-rate carrier transport, including interconnected high-pressure fluidized beds, and optimization for carrier rates, carrier
ash separation, and other operating parameters Supported carrier particles Exploiting the high-temperature stability of ceramic materials to improve carrier particles’ sinter resistance, by embedding metal nanoparticles into a ceramic matrix to create nanocomposite carrier particles Sulfur resistance of carrier The presence of sulfur, mainly as H2S in fuel streams derived and support from coal, can result in degradation of carrier performance due to the production of sulfides, both of the carrier metal and of the support, if present

and overall heat balance between the two reactors as well as being a major technological challenge. For example, the BaO2/BaO chemical loop requires 40 kg-BaO2/ kg-CH4, and applying this carrier to generate supercritical steam for a 500 MWe power plant requires a carrier transport rate of 1 kt/s (3.6 Mt/h), while also avoiding gas leakage between the reactors. Chemical looping combustion has been demonstrated in prototype facilities, at scales up to 1 MWth using various metal oxide carriers, and 6.5 MWth using CaO. Current areas of R&D focus are summarized in Table 4.12.

4.5.2 Chemical looping reforming A number of chemical looping configurations are possible that can generate syngas for liquids production or hydrogen for fuel cell and other uses. If the supply of metal oxide to the fuel oxidation reaction in Equation (4.1) is limited, partial oxidation of the fuel can be achieved, yielding a CO 1 H2 syngas: CH4ðgÞ 1 Mex OyðsÞ 2Mex Oy
1ðsÞ 1 COðgÞ 1 2H2ðgÞ

(4.3)

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For example, using NiO as carrier, the reactions would be as follows: Fuel partial oxidation CH4 1 NiO ! CO 1 2H2 1 Ni

(4.4)

Steam reforming CH4 1 H2 O ! CO 1 3H2

(4.5)

Regeneration Ni 1

1 O2 ! NiO 2

(4.6)

4.5.3 Chemical looping hydrogen production Several chemical looping variants have been demonstrated for pure hydrogen production. The example illustrated in Figure 4.7 shows hydrogen production in the carrier regeneration step, using Fe/Fe3O4/Fe2O3 as the carrier and water as the source of oxygen for regeneration. The process reactions for this concept are as follows: Fuel partial oxidation C1

1 O2 ! CO 2

(4.7)

Syngas oxidation CO 1 3Fe2 O3 ! CO2 1 2Fe3 O4

(4.8)

CO 1 Fe3 O4 ! CO2 1 3FeO

(4.9)

Fuel

Gasification

CO H2

Metal oxide reduction 2

Syngas

Fe3O4

Metal oxide reduction 2

CO2 H2O

H2 FeO

H2O

Air

Fe2O3 Metal oxidation 1

N2 Fe3O4

Metal oxidation 2

Figure 4.7 Chemical looping hydrogen production using FeO carrier.

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Carrier oxidation 3FeO 1 H2 O ! Fe3 O4 1 H2

(4.10)

Carrier combustion 4Fe3 O4 1 O2 ! 6Fe2 O3

(4.11)

The first gasification stage may be applied to the full range of carbon-based fuels. An advanced chemical looping system that uses two loops to generate H2 and CO2 streams in a coal gasification process has been demonstrated by Alstom Power. The chemical loops employed in the process are a CaS/CaSO4 loop to provide oxygen for syngas production from partial combustion of coal: Fuel partial oxidation 4C 1 CaSO4 ! 4CO 1 CaS

(4.12)

Carrier A oxidation CaS 1 2O2 ! CaSO4

(4.13)

and a CaO/CaCO3 loop to remove CO2 after water shifting CO: Water
gas shift CO 1 H2 O2CO2 1 H2

(4.14)

Carrier B carbonation CaO 1 CO2 ! CaCO3

(4.15)

Carrier B calcination CaCO3 1 heat ! CaO 1 CO2

(4.16)

This calcium chemical looping process is shown schematically in Figure 4.8.

4.6

Capture-ready and retrofit power plant

During the period of further development and demonstration of CCS technologies, and while the framework of regulations and incentives remains uncertain, there will be continued demand for the construction of new power generation plants, both to provide new capacity and to replace retiring units. If new-generation plants are

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H2

CO2

N2

CaCO3 CaS

CaO CaS

Inerts

Inerts

Air

Fuel Steam

Reducer

Calciner

Oxidizer

CaO CaSO4

CaCO3 Inerts

Figure 4.8 Calcium chemical looping hydrogen production process.

constructed without a capability to retrofit carbon capture, the operator may eventually need to either buy carbon credits to offset emissions (the so-called carbon lockin) or shut down the plant if the cost of carbon credits were to exceed the marginal cash flow per unit carbon emission. This risk can be mitigated by ensuring that the requirements for retrofitting carbon capture are considered in the plant design and construction, resulting in a capture-ready plant. In Europe, the package of energy measures agreed by the European Union Heads of Government at the 2007 Spring Energy Council recognized that CCS will be required on coal- and gas-fired generation plants to meet emissions reduction targets for 2020 and beyond. The European Union Commission has therefore proposed that all planning consents from 2010 onward will require that plants should be capture-ready, while CCS installation will be a requirement from 2020. The intention of the capture-ready requirement is to ensure that once they have been successfully demonstrated, capture technologies can be rapidly adopted to maximize the impact on cumulative emissions.

4.6.1 Capture-ready power plants To be considered as capture-ready, the retrofitting of capture systems should be both technically and economically feasible, although the latter requirement may be problematic to demonstrate at the planning stage in view of uncertainties in the future carbon market and cost of installation. The main technical factors to be considered in designing a capture-ready plant are summarized in Table 4.13, including specific considerations for pre-combustion, oxyfuel, and post-combustion capture. As noted in the table, each of the three capture options—pre- and postcombustion or oxyfueling—has specific requirements to ensure capture readiness, and the risk associated with pre-investment for capture readiness therefore differs between the options. These considerations are summarized in Table 4.14. In the case of oxyfueling, the risk that prohibitive additional requirements may emerge as the technology reaches full deployment can be mitigated by also considering the requirements for post-combustion capture when designing the plant for capture readiness, and carrying this option as a fallback.

Table 4.13 Technical factors for capture-ready power plant design Factor

Requirements

Space

Ensure space is available in the required location for additional or upgraded equipment and utilities (e.g., ASU for oxyfuel, WGS reactors for pre-combustion gasification, absorption towers for post-combustion capture; installation or upgrade of FGD, CO2 compression, possible makeup steam generation), as well as space required during construction and for maintenance access Plant capacity and Consider the energy penalty for capture when sizing the plant, depending flexibility on required net capacity Consider required load flexibility of both pre- and post-retrofit plant, and implications for plant design Utility capacity Ensure spare utility capacity or expansion capability for post-retrofit operation (e.g., electrical, control and instrumentation systems, fire and cooling water capacities, waste treatment) Capture process- Oxyfuel-ready; materials and design impact of higher combustion specific factors temperature; ensure minimum air leakage into boilers; power requirement for ASU Gasification pre-combustion capture-ready; integration of WGS reactor, H2-firing capability of gas turbines Post-combustion capture-ready; LP steam requirement for CO2 stripping; impact on steam turbine operation of reduced LP steam rate Physical Provision of tie-in points for new equipment and to existing utilities, integration process heat and cooling system Heat integration Consider both high- and low-grade heat requirements to ensure maximum efficiency of the post-retrofit plant (e.g., excess or expandable steam generation capacity) Operation Consider options to reduce the downtime incurred to install the retrofit and optimize plant operability post-retrofit CO2 storage Establish carbon storage options and requirements (e.g., access to new or existing CO2 transport infrastructure, geological or other storage site)

Table 4.14 Risks associated with capture-ready options Capture option

Captureready risk

Considerations

Post-combustion

Low

Oxyfuel combustion

Medium

Pre-combustion (IGCC plant)

Medium or high

Some viable technology options are already commercially deployed and requirements for these are well understood. Further developments may provide opportunities for easier retrofit at reduced costs, or for the use of new technologies Oxyfuel combustion has reached the demonstration scale but is not yet commercially deployed, and requirements are therefore not yet fully understood Higher base cost of IGCC relative to conventional pulverized coal plant and major plant impact of capture readiness means that the choice of IGCC over PC is currently a major pre-investment

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The largest recent new-build power plant that has been made capture-ready is the 1080 MW coal or biomass co-fired plant constructed by E.ON at Maasvlakte, Rotterdam in the Netherlands and commissioned in 2015. Post-combustion capture of up to 5.6 Mt-CO2/year could commence by 2020, with storage in depleted oil and gas fields under the North Sea.

4.6.2 Retrofitting capture capability In retrofitting carbon capture to existing power plants that have not been designed as capture-ready, all of the considerations in the previous section will have a bearing on the retrofit, and the feasibility and cost of installation will be specific to the design, age, and location of each individual plant. A key decision will be whether to accept the derating of the net power output of the plant, as a result of the energy cost of capture, or to add additional generation capacity to sustain the previous plant rating. Plant space and layout will be a limiting factor in some cases. The power derating impact of retrofitting post-combustion capture to a 500 MWe power plant is illustrated in Table 4.15 for a range of existing and future power plant efficiencies. The analysis assumes 96% capture efficiency using an amine stripping system with an energy penalty of 15% of the gross thermal power rating of the plant. Clearly, for less-efficient plant, the capital cost as well as the increased operating and maintenance cost of the post-retrofit plant, coupled with a B40% reduction in Table 4.15 Output and efficiency impact of post-combustion capture retrofit Plant type

Subcritical

Supercritical

Ultrasupercritical

Future

500 40% 0.79

500 50% 0.64

500 55% 0.58

188 38%

150 30%

136 27%

350 30% 0.039

364 40% 0.035

Plant parameters before post-combustion capture retrofit Net output (MWe) Efficiency CO2 emissions (t-C/MWh)

500 35% 0.91

Post-combustion capture penalties Capture energy penalty (MWe) Net output derating

215 43%

Plant parameters after post-combustion capture retrofit Net output (MWe) Efficiency CO2 emissions (t-C/MWh)

286 20% 0.055

313 25% 0.048

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Table 4.16 Retrofit capture projects in Electric Power Research Institute (EPRI) feasibility study Project; operator and partners

Plant capacity and type

Powerton; Midwest Generation, USA Coal Creek; Great River Energy, USA Intermountain; Intermountain Power, USA Lingan; Nova Scotia Power, Canada Bay Shore Unit 1; FirstEnergy, USA

1.5 GW subcritical pulverized coal plant 1.1 GW subcritical pulverized coal plant 1.8 GW subcritical pulverized coal plant 616 MW subcritical pulverized coal plant 129 MW petcoke-fueled CFB

net output if makeup power is not added, will result in a very substantial increase in the cost of electricity supply. The location of an existing plant in relation to potential storage sites will also be a major factor in determining the economic feasibility of retrofitting, in view of the cost of construction and operation of the required CO2 transportation infrastructure (see Chapter 23). The SaskPower operated Boundary Dam capture project (see Table 4.7) was the first commercial-scale capture retrofit to an existing power plant, while the NRG operated Petra Nova capture project is the largest currently operating at 1.6 MtCO2/year. Retrofit feasibility has also been studied for a number of other plants in the United States, as summarized in Table 4.16 (see Dillon et al., 2013). While the study concluded that retrofitting was technically feasible for all five plants, Intermountain was judged best suited due to the good baseline plant efficiency (35.6%), high capacity (1.8 GW) leading to economies of scale, availability of space for retrofit equipment, and various other plant characteristics including a steam supply well matched to post-combustion capture pressure needs and an existing FGD system.

4.7

Approaches to zero-emission power generation

In addition to the options described above, which essentially apply capture technologies to more or less conventional power generation systems, a number of alternative concepts have been proposed to achieve ZEP generation using various novel components.

4.7.1 AZEP concept: Norsk Hydro/Alstom The Advanced Zero Emission Power Plant (AZEP) concept was originally proposed by Norsk Hydro in 2002 and has been further developed by a consortium of companies including Alstom Power, Siemens, ENI Tecnologie, and Borsig. The AZEP concept, illustrated in Figure 4.9, is a Brayton-cycle gas turbine in which oxyfueled combustion of natural gas is achieved in a mixed conducting medium (MCM)

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Combustors

MCM reactor

Cooling water

Heat

O2

Bleed gas heat exchange

Heat

CO2 H2O

HRSG CO2

Natural gas

H2O

Generator

Air

Steam turbine

Oxygen-depleted air

Gas turbine

Figure 4.9 AZEP schematic flow scheme with dual-input HRSG.

membrane reactor. The underlying ion transport membrane technology is described in Chapter 8. High efficiency is achieved using an HRSG plus steam turbine bottoming cycle, shown here on a single drive shaft with the gas turbine. Heat from the MCM reactor combustion product stream is also recovered, either by driving an auxiliary CO2 and steam turbine or, as shown here, as a secondary heat input to the HRSG. Results from fabrication and initial testing of the MCM modules have achieved targets for the project, validated model predictions, and confirmed the feasibility of the AZEP concept. The test module was constructed from extruded square-channel monoliths, achieving a contact area . 500 m2/m3. Under AZEP process conditions the reactor is predicted to give an oxygen production rate of B37 mol-O2/s  m3 of module volume, equivalent to a gross power density of B15 MW/m3 of net MCM volume. Firm plans for a demonstration-scale plant have yet to be announced.

4.7.2 ZEC concept: Los Alamos National Laboratory The zero-emission coal (ZEC) concept was originally proposed by the Los Alamos National Laboratory and was further developed by the Zero Emission Coal Alliance (ZECA), later the Zeca Corporation. The ZEC concept integrates a number of advanced technologies: G

G

G

Coal gasification and steam methane reforming for hydrogen production Chemical looping (CaO2CaCO3 cycle) for CO2 removal from syngas Solid oxide fuel cells (SOFCs) for electricity production from hydrogen

As shown in Figure 4.10, the gasification step is also novel in that it starts with hydrogasification (i.e., reduction) rather than oxidation of the carbon-based fuel using a hydrogen slipstream.

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99

H 2O CH4 H2O Temp control

Gas cleanup

Gasification

H2O

Gas cleanup

CaCO3 Carbonation

H2

H2O Air

CO2 Fuel cell

Calcination

CO2 heat

CaO

Coal Ash

Sulfur and particulates

N2

H2 polishing CO2 compression

Figure 4.10 ZEC schematic flow scheme.

Table 4.17 Major reactions in the ZEC process Process

Reaction

Hydrogasification Steam methane reforming Carrier carbonation Fuel oxidation Carrier calcination

C 1 2H2 ! CH4 CH4 1 2H2 O ! CO2 1 4H2 CaO 1 CO2 ! CaCO3 2H2 1 O2 ! 2H2 O CaCO3 ! CaO 1 CO2

Since this reaction is exothermic (ΔH 5 274.9 kJ/mol), no external heat input is required for the gasification step, and injection of water can be used to control the gasifier reaction temperature. In the carbonation reactor, steam reforming of methane and carbonation of lime result in two reaction products: hydrogen and calcium carbonate. Hydrogen is oxidized in the SOFC, at an operating temperature of 1050 C, to produce electricity and steam. The latter feeds the steam reforming reaction, while additional heat recovered from the fuel cell is used to regenerate the CaO absorbent in the calcination reactor. The major reactions involved in the process are shown in Table 4.17. Laboratory-scale investigations of the hydrogasification and steam methane reforming reactions have been conducted under conditions representative of the ZEC concept and have achieved moderate to high conversion of bituminous coal to hydrogen. The final stage of the ZEC concept is the sequestration of CO2 by a mineral carbonation reaction with magnesium silicates (serpentine or olivine), as discussed in Chapter 10. The theoretical maximum efficiency of this process exceeds 90%, while accounting for heat losses and non-ideal fuel cell performance, an efficiency in excess of

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70% was considered achievable in practice. Compared to other generation processes, this extremely high efficiency would result in a substantially reduced quantity, and therefore cost, of CO2 to be disposed of per MWh generated. Unfortunately, despite its apparent promise, Zeca Corp. disappeared without trace shortly after it was recognized by Scientific American as the “Business Leader in Environmental Science” for 2003. Research work on similar systems, combining coal or biomass gasification, chemical looping combustion with CO2 capture and power generation using SOFCs is however being continued by a number of research groups (see, e.g., Aghaie et al., 2016).

4.8

References and resources

4.8.1 References Abanades, J.C., et al., 2015. Emerging CO2 capture systems. Int. J. Greenhouse Gas Control. 40, 126
166. Aghaie, M., Mehrpooya, M., Pourfayaz, F., 2016. Introducing an integrated chemical looping hydrogen production, inherent carbon capture and solid oxide fuel cell biomass fueled power plant process configuration. Energy Convers. Manage. 124, 141
154. Bailey, D.W., Feron, P.H.M., 2005. Post-combustion decarbonisation processes. Revue de l’Institut Franc¸ aise du Pe´ trole, Oil & Gas Science and Technology. 60, 461
474. Broutin, P., Kvamsdal, H., La Marca, C., van Os, P., Robinson, L., 2014. OCTAVIUS: a FP7 project demonstrating CO2 capture technologies. Energy Procedia. 63, 6194
6206. Buhre, B.J.P., et al., 2007. Oxy-fuel combustion technology for coal-fired power generation. Prog. Energy Combust. Sci. 31, 283
307. Damen, K., et al., 2014. Performance and modelling of the pre-combustion capture pilot plant at the Buggenum IGCC. Energy Procedia. 63, 6207
6214. Dillon, D., Wheeldon, J., Chu, R., Choi, G., Loy, C., 2013. A summary of EPRI’s engineering and economic studies of post combustion capture retrofit applied at various North American host sites. Energy Procedia. 37, 2349
2358. IEA GHG, 2000. Leading options for the capture of CO2 emissions at power stations. IEA Greenhouse Gas R&D Programme, Report PH3/14, Cheltenham, UK. Ishida, M., Jin, H., 1997. CO2 recovery in a power plant with chemical looping combustion. Energy Convers. Manage. 38 (Suppl.), S187
S192. Jansen, D., Gazzani, M., Manzolini, G., Van Dijk, E., Carbo, M., 2015. Pre-combustion CO2 capture. Int. J. Greenhouse Gas Control. 40, 167
187. Leung, D.Y.C., Caramanna, G., Maroto-Valer, M.M., 2014. An overview of current status of carbon dioxide capture and storage technologies. Renewable Sustainable Energy Rev. 39, 426
443. OECD/IEA, 2002. Solutions for the 21st Century, Zero Emissions Technologies for Fossil Fuels. OECD, Paris, France. Thimsen, D., et al., 2014. Results from MEA testing at the CO2 Technology Centre Mongstad. Part I: Post-combustion CO2 capture testing methodology. Energy Procedia. 63, 5938
5958.

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4.8.2 Resources CASTOR (European Union-funded project for post-combustion capture development and field trial): www.co2castor.com Chalmers University of Technology (chemical looping combustion): www.chalmers.se/en/ projects/Pages/kemcyklisk-forbranning.aspx ELCOGAS (pre-combustion capture pilot testing): www.elcogas.es/en/news-and-documents/ documents/presentations ENCAP (pre-combustion capture technology development project): www.encapco2.org European Technology Platform for Zero Emission Fossil Power Plant (ETP ZEP): www. zeroemissionsplatform.eu HTC Purenergy (modular post-combustion capture system with capacity of 1 kt-CO2/day): www.htcco2systems.com IEA GHG Oxyfuel Combustion Network: http://ieaghg.org/networks/oxy-fuel-combustionnetwork OCTAVIUS post-combustion demonstration project: www.octavius-co2.eu/ RWE (planned IGCC with CCS demonstration project): www.rwe.com/web/cms/en/2688/rwe/ innovation/projects-technologies/power-generation/fossil-fired-power-plants/igcc-ccs-powerplant Test Center Mongstad: www.tcmda.com/en US DOE National Carbon Capture Center: www.nationalcarboncapturecenter.com Vienna University of Technology (future energy technologies): www.vt.tuwien.ac.at/chemical_ process_engineering_and_energy_technology/future_energy_technology

Carbon capture from industrial processes

5

Although fossil-fueled power-generation plant accounts for the majority of large stationary sources emitting .0.1 Mt-CO2/year, similar quantities are also emitted from single sources in a number of other industries and are therefore targets for the application of carbon capture technologies. Industrial activity (excluding consumption of electrical power) accounts for around one-fifth of global CO2 emission, the most important of these emitters—cement production, iron and steel production, oil refining, and natural gas processing—are dealt with in this chapter.

5.1

Cement production

Worldwide cement production results in the emission of B2 Gt-CO2 (2015—at a global average CO2 intensity of 0.8 t-CO2/t-cement), some 5% of total anthropogenic CO2 emissions. These emissions are split roughly equally between CO2 emitted from the calcination process (B52%) and emissions from the combustion of fuel to fire cement kilns (B48%). Portland cement is a mixture of predominantly di- and tricalcium silicates (2CaO
SiO2, 3CaO
SiO2), with smaller amounts of other compounds such as calcium sulfate (CaSO4), magnesium, aluminum and iron oxides, and tricalcium aluminate (3CaO
Al2O3). The cement production process is shown schematically in Figure 5.1. After pre-heating, the milled raw feed is calcined at B860 C and then a controlled mixture of materials is sintered in a kiln, typically a horizontal rotary kiln, at a temperature of B1450 C. Calcium carbonate (CaCO3) is the primary raw material and may be in the form of crushed limestone, shells, or chalk. A variety of secondary raw materials are used as the source of silica and other minerals, including sand, shale, clay, blast furnace slag, and coal ash. The latter may be introduced directly by firing the cement kiln with pulverized coal or by importing fly or bottom ash from a coal-fired power plant. The main reaction taking place in the process is the conversion or calcining of calcium carbonate to calcium oxide, a highly endothermic reaction requiring 3.56.0 GJ/t-cement produced, depending on plant efficiency. Calcination and the other main chemical reactions proceed as follows: CaCO3 1 heat ! CaO 1 CO2

(5.1)

2CaO 1 SiO2 ! 2CaO
SiO2 ðBelliteÞ

(5.2)

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00005-2 © 2017 Elsevier Inc. All rights reserved.

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Limestone Milling Fly ash, blast furnace slag, etc.

Filtering (bag house)

Raw meal pre-heat

Raw meal silo

Rotary clinker kiln

Precalciner

Fuel Air

Clinker

Cooling

Milling

Bagging

Figure 5.1 Cement production process.

3CaO 1 Al2 O3 ! 3CaO
Al2 O3

(5.3)

4CaO 1 Al2 O3 1 Fe2 O3 ! 4CaO
Al2 O3
Fe2 O3

(5.4)

CaO 1 2CaO
SiO2 ! 3CaO
SiO2 ðAliteÞ

(5.5)

The CO2 released in the initial calcining reaction in Reaction (5.1), known as the process CO2, combined with the CO2 from combustion of the kiln fuel (coal, oil, or natural gas) yields a flue gas with a [CO2] in the range of 14%33%.

5.1.1 Post-combustion capture from cement plants Capture of CO2 from the combined flue gas can be achieved using the technologies applicable to post-combustion capture from power-generation plants, including chemical and physical solvents (Section 6.2); sorbents, particularly hightemperature sorbents (Section 7.1); and membranes (Section 8.7). Compared to “conventional” post-combustion applications, the higher [CO2] enables these technologies to achieve higher separation efficiencies in cement plant applications. Calcium looping (CaL—see Section 6.3) is widely seen as an obvious postcombustion technology for cement plants, in view of the synergy in handling and processing of the common raw materials, as well as the potential for close process integration and for purge CaO to be used in cement production. CaL was one of the four technologies that has been investigated in a 4-year project, commencing in 2014 at the Norcem operated cement plant at Brevik, Norway. The preliminary results and planned next steps in this project are summarized in Table 5.1. The advanced amine pilot was particularly successful and demonstrated the feasibility of capturing 400 kt-CO2/year, almost 50% of the Brevik plant’s total

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Table 5.1 Preliminary results and next steps in Norcem pilot tests Technology Description and preliminary results

Next steps

Amine 16-month pilot test of proprietary solvent absorption (S26) using Aker Solutions mobile testing unit; robust operation with . 90% capture rate, energy consumption lower than seen in other applications; degradation, consumption, and emissions of amines and degraded products also low; assessed TRL 9 (proven in operational environment) Solid 3-month trial of bench-scale fluidized bed sorbent reactor; assessed TRL 5 (technology valid in relevant environment) Membranes 6-month bench-scale trial using polyvinylamide (PVAm) membranes; promising membrane durability yielding 60%70% CO2 recovery; assessed TRL 5 Calcium 1-year study and lab-scale pilot; more looping rapid sorbent degradation than expected; assessed TRL 3 (experimental proof of concept)

Conceptual study commenced in 2015 for large-scale capture plant

Further testing planned with largescale pilot, aiming to achieve higher sorbent loading Immature Phase II concept led to project termination; new consortium being established to progress Phase II Developing larger scale pilot

emissions, using waste heat alone for solvent regeneration. This was considered to be the only technology likely to be mature enough for commercial deployment in the 2020 timeframe.

5.1.2 Oxygen enrichment and oxyfuel processes The addition of oxygen to the air drafting the burners—the so-called oxygen enrichment—has been practiced in cement kilns since the early 1960s and results in increased clinker production and reduced fuel consumption. Fuel consumption is reduced in part because nitrogen in the air does not need to be heated up to combustion temperature. Oxygen enrichment increases flame temperatures (to B3500 C), which has an impact on kiln refractory design and materials, and also increases [CO2] in the kiln flue gas stream, which, as noted previously, further aids post-combustion capture. Oxyfueling can also be applied as a cement plant capture technology, either in partial or full oxyfuel configurations. In a partial oxyfuel configuration only the calcining step takes place under oxygen and 60%75% of the process CO2 can be captured, while for full oxyfueling, with both the calciner and kiln operating under oxy-combustion conditions, a capture rate greater than 90% is possible. Apart from the provision

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Table 5.2 Research and development issues for oxyfuel cement production R&D

Description

[CO2] impact on reaction kinetics Burner design

Assessing the impact of high [CO2] on calcination and clinker quality Development of oxygen-drafted burners for clinker kilns, paralleling work on burners for oxyfuel steam boilers Durability of kiln refractory lining Optimal cooling systems for full oxyfuel configurations Process modeling, addressing the impact of oxyfuel on flue gas enthalpy and recirculation, heat transfer phenomena, energy demand optimization, and material flows

Kiln lining Clinker cooling Plant and process simulation

of an ASU, plant modifications are required to the calciner and pre-heaters in the case of a partial configuration and to the kiln burners, flue gas recycle (to control kiln temperature) and clinker coolers in the full oxyfuel configuration. In both cases attention would also be required to seals to prevent air ingress diluting the 85%90% CO2 off-gas stream, which could be directly compressed for transportation and storage after dehydration and possibly FGD. Research into oxyfuel technology for cement production has been ongoing since 2007, when the European Cement Research Academy started a long-term carbon CCS project. Phases I to III of this project (20072011) included technical studies and lab-scale research on both post-combustion and oxyfuel options and subsequent phases will focus on the oxyfuel route. Research topics being addressed by this and other ongoing projects are summarized in Table 5.2. Pilot-scale trials of a partial oxyfuel configuration conducted in 20112012 at the FLSmidth plant in Dania, Denmark, have also confirmed the feasibility of retrofitting for partial oxyfuel operation, as well as the stability of calciner operation and the product quality. Projected commercial-scale capture costs (h50/t-CO2) were shown to be competitive with an amine-based reference case. Further developments toward full commercial deployment can be expected from the ECRA project, which is planning toward a 2018 construction start date for a 5001000 t-clinker/day pilot plant, and also from the EU-funded CEMCAP project, which started in 2015 and will develop pilot- and demonstration-scale tests for full oxyfueling.

5.1.3 Cement production from carbon capture processes Alongside carbon capture from conventional cement production, a number of venture capital companies are developing proprietary post-combustion capture processes that aim to produce cement or cement additives by the precipitation of calcium and magnesium carbonates from seawater reacted with power plant flue gas CO2. This process is described in Chapter 22.

Carbon capture from industrial processes

5.2

107

Steel production

Integrated coal-fueled steel mills accounted for B65% of the 1.5 Gt of global steel produced in 2016, consuming B19 GJ/t-steel produced and emitting a global average of B1.8 t-CO2/t-steel produced. In the first stage of the steelmaking process, highgrade coal (anthracite) is used to fuel a blast furnace in which iron is extracted by reduction from the ore hematite (Fe2O3), using carbon monoxide as the reducing agent. The key reactions taking place in the furnace are as follows. Coal is combusted with oxygen to produce carbon dioxide and heat, while limestone, introduced as a fluxing agent to remove impurities from the iron, is calcined to produce CaO plus CO2 via the same reaction as in cement production (Reaction (5.1)). The CO2 product from these two reactions then reacts with more carbon, producing carbon monoxide: CO2 1 C ! 2CO

(5.6)

Carbon monoxide reduces the hematite ore to produce molten iron (pig iron), which is collected at the base of the furnace: Fe2 O3 1 3CO ! 2Fe 1 3CO2

(5.7)

The calcined limestone combines with impurities to form slag, primarily calcium silicate, which floats on top of the molten iron and can be removed: CaO 1 SiO2 ! CaSiO3

(5.8)

In the second stage of the steelmaking process, known as basic oxygen steelmaking (BOS), the carbon content of pig iron is reduced from a typical 4%5% to 0.1%1% in an oxygen-fired furnace. The excess carbon is oxidized to carbon monoxide, which can be recycled as a fuel gas or used as the reducing agent. At the same time other impurities, such as phosphorus and sulfur, are oxidized to form acidic oxides, neutralized by the addition of lime, and recovered as a slag that has a variety of recycling uses (see, for example, cement production in the previous section, and mineral carbonation in Section 10.3.1). Alloying elements such as chromium, manganese, nickel, and vanadium are also added at this stage to achieve the required steel composition and properties. Blast furnace gases contain close to 30% CO2, after full combustion of the CO fraction, while the overall flue gas stream from an integrated steel mill is B15% CO2. The same CO2 capture options introduced above for power-generation plant can therefore also be applied to a steel mill: G

G

Post-combustion CO2 capture from the overall flue gas stream; amine absorption (Chapter 6), membrane separation (Chapter 8), and hydrate-based capture (Chapter 9) have been studied among others. Firing the blast furnace with oxygen rather than air, yielding a furnace off-gas that is a pure CO and CO2 mixture.

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Carbon Capture and Storage

Capturing CO2 in a pre-combustion step and using hydrogen instead of carbon monoxide as the reducing agent in Reaction (5.7); that is:

Fe2 O3 1 3H2 ! 2Fe 1 3H2 O

(5.9)

The oxygen-fired blast furnace option is interesting in that it can reduce CO2 emissions from an integrated steel mill by 40%, even without CCS, due to the reduced coke consumption in the blast furnace. One pre-combustion option that has been developed in the EU-funded CACHET and CAESAR projects is the application of sorption-enhanced water-gas shift reaction to convert blast furnace gas to hydrogen, with CO2 captured in a potassium carbonate hydrotalcite-based sorbent from which it is recovered by a pressure swing. The technology is being further developed under the EU STEPWISE project (see Section 7.2). As an alternative to iron production in a blast furnace, direct-reduced iron (DRI) is produced by reducing iron ore using a mixture of hydrogen and carbon monoxide (Reaction (5.7) and (5.9)) at temperatures of 8001000 C. The first commercial CCS project at a steel plant began operating in November 2016 at the Emirates Steel DRI plant in Mussafah, Abu Dhabi. The plant produces syngas (H2 1 CO) for the direct reduction reactions by steam reforming locally abundant natural gas, and the DRI plant off-gas, containing 98% CO2, in dehydrated, compressed to scCO2 and transported 43 km for EOR at the ADNC operated BAB and Rumaitha oil fields. The project will capture 800 kt-CO2/year when fully operational. Recycling of scrap steel, using electric-powered arc or induction furnaces, accounts for B35% of overall shipped steel volume worldwide, with production of c. 550 Mt-steel reported from this type of process in 2016. Recycled steel is significantly more energy-efficient than new steel production, requiring only B25% of the energy input per unit of steel shipped. A mini-mill typically consumes 4.06.5 GJ/tsteel produced, reducing CO2 emissions by B80% to B0.3 t-CO2/t-steel. Since energy input is in the form of electrical power, the reduction of related CO2 emissions reverts to the discussion of CCS in the power-generation sector.

5.3

Oil refining

Worldwide, CO2 emissions from oil refineries account for B3% of global anthropogenic emissions and amounted to B0.9 Gt-CO2 emitted to the atmosphere in 2015. As noted in Table 2.3, the 2008 IPCC analysis of large point sources identified 638 refineries emitting an average of 1.25 Mt-CO2/year. The crude oil feed to an oil refinery is a mixture of many hydrocarbon components from methane, the lightest with a molecular weight of 16, out to long-chain molecules with molecular weights in the hundreds. The refining process, shown schematically in Figure 5.2, starts by separating out up to 10 “fractions” of this

Carbon capture from industrial processes

109

Refinery gas

Atmospheric distillation

LPG Isomerization

Hydro desulfurization

Vacuum distillation

H2

Residues

Alkylation Hydro cracking

Diesel oil

Oligomerization

Hydro conversion H2

Refinery gas

Premium gasoline

Reforming Crude oil

Catalytic cracking

Partial oxidation Steam reforming

Coke, refinery fuel

Figure 5.2 Oil refining schematic process flow scheme.

mixture by a distillation process under atmospheric pressure. Crude oil is heated to 500700 C and fed to the base of a distillation tower. As the vapor rises and cools, first the heavier and then progressively lighter components condense and are recovered as liquid fractions, with gases recovered from the top of the tower. The heavy residues recovered at the base of this initial distillation still contain significant lighter components, which are recovered in a further distillation under vacuum. The second stage in the process, known as conversion, is the breaking down of larger molecules in the heavy fractions to meet the demand for lighter and highervalue products. This “cracking” process requires the presence of either catalysts (catalytic or cat-cracking), commonly zeolite, aluminum hydrosilicate, and bauxite; steam (steam cracking); or hydrogen (hydrocracking); and temperatures ranging from 400 C (catalytic) up to 850 C (steam). Further distillation is used to separate the products resulting from the cracking process. Other important steps in the conversion process are: G

G

Catalytic reforming: a platinum or platinumrhenium catalyst is used to promote the conversion of distillates in the 100- to 150-molecular weight range (light naphtha) into heavier aromatics for use in gasoline blending and petrochemicals. Hydrogen is a byproduct of this reaction and is commonly used for hydrocracking. Alkylation: a catalyst such as hydrofluoric acid or sulfuric acid is used to convert lowmolecular-weight compounds, such as propylene (C3H6) and butylene (C4H8), into highoctane hydrocarbons used in gasoline blending. Sulfuric acid used in alkylation may be a byproduct from desulfurization (see below).

In upgrading, the final step in the refining process, undesirable compounds are removed and product characteristics are adjusted to comply with delivery

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Carbon Capture and Storage

specifications. Hydrodesulfurization (HDS), or hydrotreating, is an important upgrading step required to meet stringent environmental standards, for example, in producing low-sulfur diesel to reduce SO2 emissions. HDS is achieved by contacting the unfinished products with hydrogen at 370 C and a pressure of 6.0 MPa in the presence of a catalyst such as nickel molybdate (NiMoO4). Sulfur atoms in the hydrocarbons bond with hydrogen to produce hydrogen sulfide (H2S) and are then recovered as elemental sulfur or sulfuric acid. An oil refinery is fueled by burning top-gas from the distillation process, supplemented as needed by additional fuel oil. Some 50% of consumed energy is used to generate process heat while the remaining 50% is used for power generation, hydrogen production for hydrotreatment and hydrocracking, and plant utilities. Refinery energy consumption and attendant CO2 emissions are highly variable and depend strongly on the complexity of the refining processes employed, particularly the “deep conversion” capability required to process heavier crude oils. Typical selfconsumption ranges from 6%8% by weight of the crude oil processed for conventional conversion processes to 11%13% by weight for deep conversion, which has a significantly higher hydrogen requirement. The trend toward greater demand for lighter refined products will result in upward pressure on self-consumption in the future, making energy efficiency, process integration, and carbon capture important if growth in emissions from this sector is to be avoided. Options for capturing CO2 in the refining processes include the integration of power generation and hydrogen production in an IGCC plant, which achieves precombustion capture of CO2. Emissions from process heating can be captured either by oxyfueling or by post-combustion capture from the heater flue gases, or by also integrating process heat production into an IGCCCHP plant.

5.4

Natural gas processing

Natural gas, produced either from gas fields or as associated gas with oil production, contains varying amounts of non-hydrocarbon gases, of which CO2, N2, and H2S are the most common examples. Many large natural gas fields have CO2 concentrations of up to 20%, while some fields with . 50% CO2 are also produced. Indonesia’s Natuna field is an extreme example for commercial natural gas production and contains 71% CO2. The volume of CO2 currently produced with natural gas has been estimated at 50 Mt-CO2/year and is therefore modest compared to global emissions. However, the removal of acid gases such as CO2 and H2S from natural gas—a process known as gas sweetening—is important because the technologies developed in this area have broader application for CO2 capture in areas such as power generation. Natural gas consumption is also projected to grow more rapidly than other fossil fuels, in part due to its lower carbon intensity as a power-plant fuel. Exploitation of more difficult gas reserves, often with higher CO2 content, will also require capture and storage if increasing emissions from this sector are to be avoided.

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CO2 removal from natural gas is now a mature technology that has been applied on an industrial scale since the 1980s. The end-use specification, whether for pipeline transport into a supply grid or for liquefaction and onward transport as liquefied natural gas (LNG), requires the CO2 concentration to be reduced to 23 mol%. Various technologies have been applied, including physical and chemical solvents, membranes, and cryogenic separation, with the preferred technology in any specific application depending on the feedstock and required output compositions. Statoil’s Sleipner field development in Norway is the longest running example of CCS from natural gas, in this case associated gas from oil production; since start-up in 1996, about 1 Mt-CO2 has been captured each year by amine absorption and injected into the underlying Utsira aquifer. The details of specific technologies and applications in natural gas processing are covered in Chapters 69, while further references to the Sleipner project will be found throughout Part III.

5.5

Pulp and paper production

The global paper and pulp industry accounts for around 2% of total direct CO2 emissions from industrial sources—around 0.5 Gt-CO2/year. Worldwide, the most commonly used papermaking process is the Kraft process, in which chemicals are used to free cellulose fibers in the raw material from the lignin binding agent. The main steps in the Kraft process, using wood as the raw material, are shown schematically in Figure 5.3 (optional steps shown in lighter shading). After debarking and chipping the raw material, extraction of the cellulose fibers to be used in papermaking is achieved in the Kraft process by the addition of sodium sulfide (chemical pulping). Other processes use

Pulp making

Wood preparation

Chemical pulping

Chemical recovery

Bleaching

Pulp drying

Lime kiln

Market pulp

Paper making

Forming

Stock preparation

Re-pulping

Pressing

Pre-drying

Surface treatment

Finishing

Final drying

Paper/board product

Figure 5.3 Schematic flow diagram of the Kraft pulping and papermaking process. Source: After Kong, Hasanbeigi, and Price, 2014.

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mechanical and thermo-mechanical methods to separate the fibers but these are more energy intensive. The digested pulp is then separated into three components; “black liquor”—containing dissolved combustible components such as lignin and hemicellulose—is evaporated and combusted as fuel, and the pulping chemicals are recovered from the residual “green liquor” by the addition of lime (CaO) in a causticizer. The resulting lime mud (CaCO 3) is regenerated in a lime kiln—identical to the calcination step in cement production (see Reaction (5.1)). The most energy-intensive steps in the papermaking process are drying of the final paper product (25%30% of total energy requirement), evaporation of black liquor during chemical recovery, and lime mud calcination in the lime kiln, the latter also generating high levels of process CO2. Most paper mills include their own power generation island and the main CO2 mitigation option is in applying the capture technologies described in Chapter 4 to these plants. The byproducts of raw material preparation (e.g., wood bark and fines) and the chemical pulping process (e.g., concentrated black liquor) are also used to fuel power generation, either in conventional boilers or in more efficient gasification combined cycle plant. These fuels are also combusted directly in process boilers, for example, in black liquor evaporation which is a major energyconsuming step, and CO2 capture from these boilers—by either post-combustion or oxyfueling—will be important to minimize emissions. Process CO2 from the lime kiln can also be captured using the approaches described above for the cement industry, such as oxyfuel combustion in the kiln. Residues such as boiler ash from various parts of the process can also be used as a raw material for the production of PCC. This is an important mineral filler used in paper production and the production process, which also captures CO2, is described in Chapter 22. Because the carbon capture opportunities in the pulp and paper industry follow closely on those in the power and cement industries, industry-specific work has been limited to desk studies and reviews. As well as the financial hurdles, the need for a well-established and geographically dispersed transportation and storage infrastructure is noted as an important enabler, particularly since many mills emit less than 0.5 Mt-CO2/year. It is also worth noting that a large part of the CO2 emitted by the industry—almost 80% in Europe—results from biofuel combustion, and energy efficiency improvements could reduce the fossil fuel use or energy import of many mills to zero. CCS in the pulp and paper industry would therefore be largely BECCS, and wide application would make the industry carbon negative.

Carbon capture from industrial processes

5.6

113

References and resources

5.6.1 References Bjerge, L., 2015. Norcem CO2 Capture Project. Presented at the TEKNA CO2 Conference, Trondheim, Norway. 9 January 2015. Carrasco-Maldonadoa, F., Spo¨rl, R., Fleiger, K., Hoenig, V., Maier, J., Scheffknecht, G., 2016. Oxy-fuel combustion technology for cement production—state of the art research and technology development. Int. J. Greenhouse Gas Control. 45, 189199. Decroocq, D., 2003. Energy conservation and CO2 emissions in the processing and use of oil and gas. Revue de l’Institut Franc¸ais du Pe´trole, Oil & Gas Science and Technology. 58, 331342. Gazzani, M., Romano, M.C., Manzolini, G., 2015. CO2 capture in integrated steelworks by commercial-ready technologies and SEWGS process. Int. J. Greenhouse Gas Control. 41, 249267. Gielen, D.J., 2003. CO2 removal in the iron and steel industry. Energy Convers. Manage. 44, 10271037. Hasanbeigi, A., Arens, M., Price, L., 2014. Alternative emerging iron making technologies for energy-efficiency and carbon dioxide emissions reduction: a technical review. Renewable Sustainable Energy Rev. 33, 645658. Hoenig, V., Hoppe, H., Emberger, B., 2007. Carbon Capture Technology—Options and Potentials for the Cement Industry. European Cement Research Academy, Report TR 044/2007. IEAGHG, 1999. The Reduction of Greenhouse Gas Emissions from the Cement Industry. IEA Greenhouse Gas R&D Programme, Cheltenham, UK, Report PH3/7. Knudsen, J.N., Bade, O.M., Askestad, I., Gorset, O., Mejdell, T., 2015. Pilot plant demonstration of CO2 capture from cement plant with advanced amine technology. Energy Procedia. 63, 64646475. Kong, L., Hasanbeigi, A., Price, L., 2014. Emerging Energy-Efficiency and Greenhouse Gas Mitigation Technologies for the Pulp and Paper Industry. Lawrence Berkeley National Laboratory, USA, LBNL Paper LBNL-5956E. Kuramochi, T., Ramı´rez, A., Turkenburg, W., Faaij, A., 2012. Comparative assessment of CO2 capture technologies for carbon-intensive industrial processes. Prog. Energy Combust. Sci. 38, 87112. Mollersten, K., Gao, L., Yan, J.-Y., Obersteiner, M., 2004. Efficient energy systems with CO2 capture and storage from renewable biomass in pulp and paper mills. Renewable Energy. 29, 15831598. Schneider, M., 2015. ECRA’s Oxyfuel Project. Presented at the International CCS Conference, Langesund, Norway. 2021 May 2015. Wilkinson, M.B., et al., 2003. CO2 capture from oil refinery process heaters through oxyfuel combustion. In: Gale, J., Kaya, Y. (Eds.), Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies. Elsevier, Oxford, UK.

5.6.2 Resources CEMCAP (EU Horizon 2020 funded project to reduce emissions from cement production): www.sintef.no/projectweb/cemcap. Concrete Sustainability Hub (MIT research group dedicated to improving the sustainability of concrete production and use): cshub.mit.edu.

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ECRA (ongoing steel industry CCS project): www.ecra-online.de. Norcem (developing capture technology for the cement industry): www.norcem.no/en/ carbon_capture. Technische Universita¨t Hamburg-Harburg (oxyfuel cement production RD&D): www.tuharburg.de/alt/iet/research.html. World Steel Association (global steel industry approach to CO2 emissions reduction): www. worldsteel.org/publications/position-papers/Steel-s-contribution-to-a-low-carbon-future. html. EU STEPWISE project: www.stepwise.eu.

Absorption capture systems

6

Processes for removing CO2 from a gas stream, based on chemical or physical absorption, have been applied on an industrial scale for more than 50 years, driven by the requirement to treat natural gas to a sales gas specification with low content of acid gases, such as CO2 and H2S, or by the need to condition syngas from coal gasification as a feed for other chemical processes such as Fischer
Tropsch liquids production. These processes have typically been applied to gas streams with a relatively high acid gas partial pressure and have provided an extensive body of experience from which to address the more challenging problem of CO2 recovery at lower partial pressure, e.g., from combustion flue gases at typically 10
20 kPa CO2 partial pressure or, in the extreme, the direct capture of CO2 from air at a partial pressure of B40 Pa.

6.1

Chemical and physical fundamentals

Processes to capture CO2 based on absorption are distinguished depending on whether the solvent either reacts chemically with the sorbate (CO2) to form chemical compounds from which the CO2 is subsequently recovered or is chemically inert and absorbs the sorbate without a chemical reaction. These distinct processes are termed chemical and physical absorption, respectively. The key requirements for absorption processes to achieve cost efficiency are as follows: G

G

G

G

Fast absorption and desorption rates to minimize equipment size High loading of CO2 per unit solvent volume, coupled with low solvent cost Low heat of desorption to reduce the energy penalty for solvent regeneration Solvent tolerance to contaminants, to reduce degradation and unwanted by-product formation

6.1.1 Chemical absorption Chemical absorption for CO2 capture is based on the exothermic reaction of a sorbent with the CO2 present in a gas stream, preferably at low temperature. The reaction is then reversed in a so-called stripping, or regeneration, process at higher temperature. Chemical absorption is particularly suitable for CO2 capture at low partial pressure, with amine or carbonate solutions being the predominant solvents.

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00006-4 © 2017 Elsevier Inc. All rights reserved.

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Amine-based absorption Amines are organic compounds derived from ammonia (NH3) in which one or more of the hydrogen atoms are replaced by organic components or substituents. Depending on the number of substituents these compounds are termed primary, secondary, or tertiary amines. The simplest primary amine is methylamine (CH3NH2 or CH5N), with one hydrogen replaced by a methane (CH3) group. To simplify the nomenclature, the organic group is commonly replaced by R, giving R1-NH2, R1R2-NH, and R1R2R3-N for primary, secondary, and tertiary amines, respectively. The most commonly used amine for CO2 capture is ethanolamine (or monoethanolamine (MEA)), a primary amine with R5CH2CH2OH. In an aqueous solution, MEA acts as a weak base, which can neutralize an acidic molecule such as CO2. In this reaction, a weakly bonded compound called a carbamate is formed (Figure 6.1): 2 2R-NH2 1 CO2 ! R-NH1 3 1 R-NHCOO 1 heat

(6.1)

the heat of absorption for CO2 in MEA being 2.0 GJ/t-CO2. Two other reactions also occur that result in CO2 dissolution, base-catalyzed hydration of CO2: 2 R-NH2 1 CO2 1 H2 O ! R-NH1 3 1 HCO3 1 heat

(6.2)

and the formation of carbonic acid: CO2 1 H2 O ! H2 CO3

(6.3)

However, compared to the rate of Reaction (6.1) for MEA, the other two reactions make a minimal contribution to the overall CO2 absorption rate. For a secondary amine, the equivalent carbamation reaction would be: 1 2 2 2R1 R2 -NH 1 CO2 ! R1 R2 -NH1 2 1 R R -NCOO 1 heat

(6.4)

While for tertiary amines, the reaction is the base-catalyzed hydration of CO2: R1 R2 R3 -N 1 CO2 1 H2 O ! R1 R2 R3 -NH1 1 HCO2 3

(6.5)

O– 2

HO

NH2 + CO 2

Figure 6.1 Carbamate ion structure.

HO

N+ H3

OH O

N H

Absorption capture systems

117

The carbamate ion nitrogen
carbon bond is easily broken down by the application of heat, leading to the reverse reaction in which the original solvent is regenerated. For example, for MEA regeneration, typically at B100
120 C: 2 R-NH1 3 1 R-NHCOO 1 heat ! 2R-NH2 1 CO2

(6.6)

Regeneration of the solvent in Reaction (6.2) similarly proceeds by the reverse reaction: 1 HCO2 3 1 R-NH3 1 less heat ! R-NH2 1 CO2 1 H2 O

(6.7)

The application of these reactions to the removal of CO2 from flue gases is described in Section 6.2.1. The maximum CO2 loading of the MEA solvent that can be theoretically achieved in Reaction (6.1) is 0.5 (i.e., one mole CO2 in two moles of solvent), while the bicarbonate forming reactions (Reactions (6.2) and (6.5)) achieve twice this loading (one mole of CO2 per mole of solvent). This higher loading can be achieved in practice by steric hindrance of the carbamation reaction—i.e., the use of a larger amine molecule in which the carbamation reaction is hindered because of the physical structure of the amine molecule. Although the energy required for regeneration is lower for these hindered amines, this is compensated by the slower overall reaction rates, and a rate promoter such as piperazine (see next section) is commonly added to the solvent. Proprietary formulations of sterically hindered amine solvents with rate promoting additives are used in the KEPCO/MHI process summarized in Table 6.1, and strong bicarbonate forming systems are also under investigation in the ongoing (2014
17) EU HiPerCap research project (see Section 6.3.3 and Resources). When considering the three key requirements for effective solvents—fast reaction rate, low regeneration energy, and high loading capacity—the choice between primary, secondary, and tertiary amines is not straightforward. In general, the relative merits are as follows: for reaction rate, primary, followed by secondary, then tertiary, while for regeneration energy and loading capacity, the priority order is reversed. Mixing primary, secondary, and tertiary amines in blended amine solvents is one approach to combine the advantages of the different amine types—e.g., increasing the reaction rate of a tertiary amine such as methyldiethanolamine (MDEA) by adding a secondary amine activator to produce activated MDEA (aMDEA). The sorption reaction rate is important because this affects the size of the physical process equipment required for a given treatment gas flow rate (see Section 6.2.1); a faster reaction allows equipment to be smaller, thus reducing the capital cost of the capture plant. Oxidative and thermal degradation of amines results in the formation of a range of organic reaction products. SO2 and NO2 also react with amines to form heatstable salts (sulfates and nitrates), which lead to a loss of solvent absorption capacity and additional requirements for solvent makeup and waste stream disposal.

Table 6.1 Amine-based CO2 capture systems in commercial use and under development Process

Description

Kerr-McGee/ABB Lummus Crest Technology process

1 SO2 tolerant to 100 ppm Higher solvent concentration 2 High solvent flow rate and Process improvements to reduce regeneration heat requirement oxygen degradation of solvent 2 Lower oxygen tolerance leading to solvent degradation Improved solvent formulation to Inhibited aqueous MEA solvent (30% MEA by weight). Single 1 Improved oxygen tolerance with low corrosivity increase reaction rate and reduce train capacity up to 1000 t-CO2/day, with FEED completed absorber tower height on a 4776 t-CO2/day envisaged Higher solvent capacity leading to 2 Higher solvent consumption lower solvent flow rate and reduced (1.5
2.0 kg/t-CO2) regeneration energy cost Process improvements in Low SO2 tolerance (,10 ppm) demonstration-scale plants Further development of hindered Sterically hindered amine solvents (KS1, KS2, KS3) plus a rate 1 Low regeneration heat requirement amines with lower heat of promoter. Single train capacity up to 4776 t-CO2/day at the Petra Nova site desorption 1 Low solvent flow rate, Reducing other process heat degradation, and losses requirements 2 Higher solvent cost compared Reducing solvent losses to MEA Process improvement in 2 Low SO2 tolerance (,10 ppm) demonstration-scale plants World’s first commercial-scale post-combustion CCS 1 Low regeneration energy and Process optimization in commercialdeployment at SaskPower’s coal-fired Boundary Dam power faster kinetics compared to scale plant plant in Canada conventional amines 1 High loading capacity 1 Improved oxidative and thermal degradation resistance

Fluor Econamine FG Plust process

Kansai/Mitsubishi KEPCO/MHI process

Shell Cansolvs process

MEA solvent, using low amine concentration (15%
20%) to limit corrosion. Single train capacity up to 400 t-CO2/day

Application limits/operational conditions

Further development focus areas

Absorption capture systems

119

Amine degradation products are a hazardous waste which requires treatment prior to disposal. Conventional aerobic or anaerobic wastewater treatment can be used for diluted streams, while concentrated waste (such as ARW—see Section 6.2.1) on account of its calorific value (LHV B16 GJ/t) can be combusted, e.g., in cement kilns. A further operational disadvantage of amines is their corrosivity, necessitating the use of corrosion-resistant alloys or corrosion inhibitors in equipment experiencing high temperatures or high CO2 loading.

Aqueous carbonate
based absorption The dissolution of carbonate rocks by carbonic acid—formed from CO2 and rainwater—is a process that removes CO2 from the atmosphere as part of the geochemical carbon cycle (Chapter 1) and proceeds according to the reactions: H2 O 1 CO2 ! H2 CO3

(6.8)

CaCO3 1 H2 CO3 ! Ca21 1 2HCO2 3

(6.9)

Acceleration of this natural process has been proposed as a method of removing CO2 from power plant or cement plant flue gases, using a reactor in which the gas is flowed through a bed of crushed limestone, wetted by a continuous flow of water. Rather than regenerating the limestone sorbent, the concept is that the bicarbonaterich effluent stream would be disposed of into the ocean. In view of the ocean storage aspect, this accelerated weathering of limestone (AWL) process is described further in Section 20.4. Regenerable aqueous carbonate solutions have also been widely applied for H2S and CO2 capture by chemical absorption in a range of petroleum and other industrial applications. A potassium carbonate (K2CO3) absorption system, known as the Benfield process, is based on the following reaction: K2 CO3 1 CO2 1 H2 O22KHCO3

(6.10)

the rate determining step being the formation of the bicarbonate ion: CO2 1 OH2 2HCO2 3

(6.11)

This process has the advantage of lower desorption energy requirements compared to amine-based systems (0.9
1.6 GJ/t-CO2 vs 2.0 GJ/t-CO2 for MEA) balanced by the disadvantage of lower rates of reaction at the low CO2 pressures typical for flue gases, controlled by Reaction (6.11). However, the rate of absorption and solvent absorption capacity can be increased by adding reaction rate promoters such as amines or amino acids, boric acid, carbonic anhydrase (CA) (see below) or piperazine to the reaction. Piperazine is a cyclohexane ring with two opposing carbon atoms replaced by amine functional groups (Figure 6.2).

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Carbon Capture and Storage

H

H

H

H C

H H

C C

C

H

C

C

H

H

H

H

C

C

H H H

N

H

Cyclohexane

H

C

C

H

C

C

H

H

N

H

Piperazine

Figure 6.2 Cyclohexane (C6H12) and piperazine (C4H10N2).

The piperazine (PZ) enhanced reaction scheme can be simplified as follows, following Reactions (6.10) and (6.11): KHCO3 ! K1 1 HCO2 3

(6.12)

2 PZ 1 HCO2 3 2PZCOO 1 H2 O

(6.13)

2 PZCOO2 1 HCO2 3 2PZðCOO Þ2 1 H2 O

(6.14)

The carbamate reactions (Reactions (6.13) and (6.14)) dominate the CO2 absorption process and, as for the straight K2CO3 system, require significantly lower heat input than MEA for the regeneration reaction.

Enzyme-catalyzed chemical absorption In aqueous absorption systems, the hydration of dissolved CO2 to form bicarbonate ions (HCO2 3 ) according to Reaction (6.15): 1 CO2 1 H2 O 2 HCO2 3 1H

(6.15)

is commonly either a rate limiting step (e.g., in the case of K2CO3) or a secondary absorption mechanism that makes minimal contribution to the overall CO2 loading of the solvent solution (e.g., for amine systems). The use of the enzyme CA as a catalyst to address these limitations has been widely investigated since it was first proposed in 1961. Carbonic anhydrases are a broad class of enzymes found in all living organisms —from microbes to man—that catalyze the hydration of CO2 (see Section 10.1.3). The catalyst has the largest effect if it is dissolved in the solvent solution, typically at ,1 g/l, with a 12-fold rate improvement observed in laboratory tests with K2CO3 solvent. Since the enzyme is susceptible to process conditions such as high temperatures and pH, it can be protected from these extremes by immobilization in microparticles, applied as a coating to the absorber tower packing, or in membranes.

Absorption capture systems

121

Aqueous ammonia-based absorption The reaction of ammonia and its derivatives with CO2 also has the advantage of lower heat of reaction than the equivalent amine-based reactions, opening up the possibility of significant energy efficiency improvement and cost reduction compared to an amine-based system. Ammonia may be used directly, with a lean solvent containing 10%
15% NH3 by weight in water giving the lower overall energy requirements. Aqueous reactions with CO2 and water produce a range of reaction products—ammonium carbonate ((NH4)2CO3  H2O), ammonium bicarbonate (NH4HCO3), ammonium sesquicarbonate ((NH4)2CO3  2NH4HCO3), and ammonium carbamate (NH2COONH4)— depending on the operating temperature and CO2 loading. The various reaction products may reach their respective solubility limits, in which case the rich solvent will form a slurry. An aqueous solution of ammonium carbonate ((NH4)2CO3) may also be used as a solvent, reacting with water to form ammonium bicarbonate (called the AC/ABC reaction): ðNH4 Þ2 CO3 1 CO2 1 H2 O22NH4 HCO3

(6.16)

Ammonia-based scrubbing is also applied to flue gas SO2 and NO2 removal, as described in Chapter 3. The use of ammonia for CO2 capture potentially allows a single solvent system to be used for multicomponent flue gas emissions control.

Sodium hydroxide
based absorption The principal reactions taking place in the absorption of CO2 by sodium hydroxide are firstly carbonic acid formation from CO2 and water, and second sodium bicarbonate or carbonate formation from sodium hydroxide (NaOH) and carbonic acid according to: H2 CO3 1 NaOH ! NaHCO3 1 H2 O

(6.17)

NaHCO3 1 NaOH ! Na2 CO3 1 H2 O

(6.18)

The relative proportions of the carbonate and bicarbonate end products can be controlled by adjusting the pH in the absorption stage, e.g., by adding hydrochloric acid (HCl). Unlike other solvents, regeneration of sodium hydroxide cannot be achieved by a mild temperature swing and requires a further chemical step. For example, the addition of lime (CaO): CaO 1 H2 O ! CaðOHÞ2

(6.19)

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Carbon Capture and Storage

CaðOHÞ2 1 Na2 CO3 ! 2NaOH 1 CaCO3

(6.20)

Calcium carbonate is separated from the resulting slurry and is in turn regenerated by heating to drive off water, followed by calcination at B900 C: CaCO3 1 heat ! CaO 1 CO2

(6.21)

Depending on the way in which heat is provided to the calciner, the off-gas may be either a pure CO2 stream that can be compressed for storage, or a CO2-enhanced flue gas stream (B20% CO2), from which CO2 would then have to be re-captured, e.g., if the process was being used for direct air capture (see Section 6.3.5). This process has the advantage of using chemicals that are inexpensive and abundantly available, but a significant disadvantage is the high energy requirement for CaCO3 recovery in the calciner (15 GJ/t-C). An alternative solvent recovery route has been investigated using the solid-state reaction between sodium carbonate and sodium trititanate (Na2O  3TiO2), the so-called titanate cycle. The solid carbonate and trititanate are heated to B860 C, at which point the pentatitanate is formed and CO2 is released: 5ðNa2 O  3TiO2 ÞðsÞ 1 7Na2 CO3ðsÞ ! 3ð4Na2 O  5TiO2 ÞðsÞ 1 7CO2ðgÞ

(6.22)

The sodium pentatitanate is then cooled and leached with water to regenerate the caustic solvent: 3ð4Na2 O  5TiO2 ÞðsÞ 1 7H2 O ! 14NaOHðaqÞ 1 5ðNa2 O  3TiO2 ÞðsÞ

(6.23)

Overall, including heating and heat recovery, the titanate cycle has approximately half the energy requirement of the calcination route at B2.9 GJ/t-CO2 versus B5.7 GJ/t-CO2 calcination. An alternative to regeneration of the caustic solvent is to continuously produce sodium hydroxide by electrolysis of NaCl brine: 2NaCl 1 2H2 O ! Na1 1 Cl2 1 H1 1 OH2 ! 2NaOH 1 Cl2 1 H2

(6.24)

This has been proposed for a capture system that would produce solid sodium bicarbonate as a product stream (Section 6.3.5).

Phase-change solvents A new class of solvents—phase-change solvents—have been developed through R&D work aimed at improving amine solvent performance and offer several advantages in terms of solvent loading, regeneration energy requirements, stability, and corrosivity when compared to conventional amine solvents. Two types of phase-change have been exploited in this way, bi-phasic liquid systems and precipitating systems.

Absorption capture systems

123

Bi-phasic solvents are a class of mixed solvents which form two immiscible liquid phases under certain conditions of temperature and CO2 loading—one phase being CO2-rich and the other CO2 lean. These solvents operate as a single homogeneous phase during gas absorption, typically at B40 C, and separation is induced either directly as a result of CO2 loading or after heating to a regeneration temperature above the liquid phase separation temperature. Systems which become immiscible on heating are termed thermomorphic bi-phasic solvents (TBS). After separation of the two phases in a liquid
liquid separator, only the rich phase then needs to be regenerated, typically at B80
90 C, the CO2 lean light phase being mixed with the regenerated solvent and returned to the absorber. The regeneration energy requirement is significantly reduced due to the lower operating temperature and the reduced volume of solvent that needs to be stripped when compared to MEA. In precipitating systems, a high CO2 loading is achieved without the solvent becoming saturated by removing a precipitated reaction product containing CO2 (e.g., as a carbamate, carbonate, or bicarbonate), while recirculating the CO2 lean supernatant liquid to the absorber. The precipitate is removed as a concentrated slurry from which CO2 is released on heating, regenerating the solvent. A variety of solvents have been tested for this application, including potassium carbonate (the UNO MK3 process developed by CO2CRC), hydrous ammonium carbonate, precipitating ammonium bicarbonate, gamma aminopropyl tetramethyldisiloxane (GAP-0), a solvent developed by GE Global Research, precipitating GAP-0 carbamate, and amino acid salt solutions (e.g., salts of taurine (C2H7NO3S), proline (C5H9NO2), and sarcosine (C3H7NO2)) which produce various precipitates depending on amino acid structure and solubility. The main advantages of precipitating systems are the high solvent loading, achieved by removing the carbonated reaction product, and the possibility to regenerate the solvent at high-pressure, reducing subsequent energy required for CO2 compression. Challenges with these systems include the co-precipitation of salts containing contaminants such as SO2 and NOx which cannot be easily separated from CO2 derived precipitates, and the potential for equipment fouling due to precipitate build-up.

6.1.2 Physical absorption Physical absorption processes use organic or inorganic physical solvents to absorb acid gas components rather than reacting with them chemically. CO2 absorption by a physical solvent is determined by the vapor
liquid equilibrium of the mixture via Henry’s law, which states that, at a given temperature, the amount of a gas dissolved in unit volume of a solvent is proportional to the partial pressure of the gas in equilibrium with the solvent. Thus the solubility of CO2 (KCO2) is expressed as:

124

Carbon Capture and Storage

KCO2 5 CCO2 =PCO2 5 1=KHCO2

(6.25)

Volumes CO2/Volume CH3OH

where CCO2 is the dissolved concentration of CO2, PCO2 is the CO2 partial pressure, and KHCO2 is the Henry’s law constant for CO2. Equation (6.25) shows that the concentration of a solute such as CO2 in a solvent is proportional to its partial pressure above the solvent. In physical absorption processes for CO2 capture, high solvent loading will therefore be achieved for feed gas streams at high CO2 partial pressure. Physical absorption has the advantage over chemical absorption in that the heat required for desorption is significantly lower; however, this also necessitates low operating temperatures at the absorption stage to achieve high solvent loading. Methanol (CH3OH) is used as a physical solvent in CO2 separation from natural gas in the Rectisol process (Section 6.2.2). The dependence of CO2 solubility in methanol on temperature and partial pressure is illustrated in Figures 6.3 and 6.4. 100 80 60 40

CO2 Solubility at 0.1 MPa pressure

20 0

–60

–40

–20

0

Temperature (∞C)

Figure 6.3 Temperature dependence of CO2 solubility in methanol.

CO2 partial pressure (MPa)

1.0 0.8 –15°C

0.6

–30°C

0.4 0.2 0

50

100

Volumes CO2/Volume CH3OH

Figure 6.4 Partial pressure dependence of CO2 solubility in methanol.

150

Absorption capture systems

125

Solubility rises steeply at reducing temperatures below
40 C, enabling very effective separation of CO2 at operating temperatures in the range from
60 C to
70 C. Figures 6.3 and 6.4 also illustrate that from an absorption operating point at low temperature, high-pressure, or both, a change in operating conditions to higher temperature or lower pressure will result in release of the solute as a result of lower solubility. Regeneration of a physical solvent can thus be achieved by an increase in temperature (temperature swing) or a reduction in pressure (pressure swing). Other physical solvents that have been applied to CO2 capture include propylene carbonate (C4H6O3) in the Fluor process, and dimethyl ethers of polyethylene glycol (DMEPG) (CH3(CH2CH2O)nCH3) in the Selexols process (see Table 6.2). Unlike chemical sorbents, physical sorbents are chemically inert to the treated gas stream, avoiding the formation of heat-stable salts that can be problematic for chemical absorption processes.

6.2

Absorption capture applications

Due to the relative maturity of the technology, absorption-based systems—both chemical and physical—dominate the list of large-scale operating and planned capture projects and are used in the world’s largest operating capture projects in the power generation and natural gas processing sectors.

6.2.1 Chemical absorption applications Amine-based chemical absorption Chemical absorption processes using a variety of amine-based solvents have been deployed for post-combustion CO2 capture, with installed single train capacities now reaching B4800 t-CO2/day in the Petra Nova project (see below). Figure 6.5 illustrates the process flow scheme of a typical amine-based capture system. Flue gas entering the process at close to atmospheric pressure is cooled to the required operating temperature in the region of 40
60 C. Cooling by direct water contact will also beneficially remove fine particulate matter from the gas stream. The lean solvent (low content of CO2 reaction products) is brought into contact with cooled flue gas in a packed absorber tower (amine scrubber). Flue gas exiting the top of the absorber is water washed, to reduce the entrainment and carryover of solvent droplets and vapor, and is then vented to the atmosphere. Rich solvent (high content of CO2 reaction product) exits the base of the scrubber and is pumped to the top of the amine stripping tower. A heat exchanger heats the rich solvent, recovering heat from the regenerated solvent cycling back to the absorber. The stripping tower typically operates at 100
140 C and at marginally higher pressure than the absorber. The heat required to reverse the absorption reaction, releasing pure CO2 and regenerating the lean solvent, is supplied by a reboiler, which would typically be integrated into the steam cycle of the host plant. The reboiler energy requirement for a 30 wt% MEA solvent is 3.7 GJ/t-CO2, and this

Table 6.2 Absorption technologies and RD&D summary Absorption technology

Advantages

Disadvantages

RD&D focus areas

Physical absorption Fluor process (propylene carbonate)

Rectisol process (chilled methanol)

Selexol process (DMEPG)

Well-proven technology with 50 1 years of commercial application High selectivity for CO2 relative to methane Non-corrosive solvent

Low H2S tolerance in feed gas stream Feed gas must be dehydrated due to high water solubility Irreversible reaction with CO2 and water at 90 C precludes temperature swing regeneration High refrigeration energy cost Solvent volatility and emissions concerns

High selectivity for H2S and CO2 Able to remove many contaminants in a single process Low solvent cost Higher selectivity for H2S over CO2 Long-proven commercial Feed gas must be dehydrated due application in gasification to high water solubility projects Well-proven technology with Required high partial pressure of 301 years of commercial CO2 application Chemically inert solvent not High solvent viscosity subject to degradation; very low vapor pressure

Additives to reduce solvent costs

Process optimization to reduce energy requirements and operating costs

Non-aqueous solvent allows low- High solvent costs cost carbon steel plant construction Dual-stage process can capture CO2 and H2S, e.g., from syngas

Chemical absorption Amine systems (e.g., MEA, DMEA)

Well-proven technology with extensive commercial application, leading to low capital costs Range of solvents have been developed

Technical and economic benchmark for other solvent systems

Low amine concentrations to resist Evaluation of new amine-based solvents, including amine-blends with lower heat of adsorption, corrosion also limit loading higher loading (e.g., strong bicarbonate formers), capacity and reduced degradation Hazardous degradation products Catalyzed absorption and regeneration/desorption (e.g., solid acid catalysts, CAs) Low tolerance to SO2, NOx, and O2 in flue gas High energy requirement for sorbent regeneration Solvent loss due to mist formation

Bi-phasic liquid solvents

Higher solvent loading capacity Typically higher loaded solvent Regeneration at higher pressure viscosity than amines, inducing and lower temperature reduces higher process pressure drops energy requirement

Additives to improve system performance (higher amine concentration and loading, faster reaction rate, inhibited solvent degradation) Process improvements to reduce energy requirements, improve heat integration, increase solvent capacity (e.g., absorber tower intercooling), reduce solvent loss Quantum-chemical modeling to predict solvent properties based on molecular structure Performance of precipitating amine 1 amino acid solvents Regulation of solvent phase-change Alternative desorption techniques (e.g., ultrasonic and extractive) Identification of degradation products (Continued)

Table 6.2 (Continued) Absorption technology

Potassium carbonate systems

Aqueous ammonia

Chilled ammonia

Advantages Lower corrosivity than standard amine solvents Higher solvent loading capacity Lower regeneration energy requirement Lower corrosivity Low solvent cost

Low regeneration energy requirement Lack of solvent degradation during the absorption and regeneration cycle Low solvent cost High-pressure regeneration Tolerant to O2 and other contaminants Sellable ammonium sulfate and ammonium nitrate fertilizer by-products Low regeneration energy requirement

Disadvantages

Slow reaction rate without promoters such as piperazine High cost of additives such as piperazine System fouling due to reaction product precipitation

High solvent volatility requires reduced operating temperature High solvent loss during regeneration at high temperature

RD&D focus areas Development and validation of liquid:liquid phasechange thermodynamic models Energy saving through improved tower packing and multistage stripping

Alternative additives (e.g., CA, amino acids) to improve CO2 absorption rate and reduce stripping heat requirement Precipitating systems to reduce regeneration energy Increasing solvent loading and reaction rate, inter alia through process optimization Reducing solvent losses, e.g., using ILs as additives

Integration with industrial production of ammonium bicarbonate fertilizer

Near-freezing operating conditions required to limit solvent losses

Process optimization in demonstration-scale plant

Task-specific and reversible ILs

Sodium hydroxide

Lack of solvent degradation during the absorption and regeneration cycle Low solvent cost Sellable ammonium sulfate fertilizer by-product Very low volatility and solvent loss Very low heat of adsorption (10%
15% of MEA) High chemical and thermal stability Dual-mode (physical plus chemical solvents) with high loading capacity Less corrosive than amines Low-cost and abundance of required chemicals All process steps are currently proven technologies, applied in other industries

Potential for fouling due to ammonium bicarbonate solids

Reducing solvent emissions by improving water wash Improved heat integration and control systems

High production cost of ILs

Synthesis and performance testing of new, lower cost ILs, e.g., using amino acids High viscosity, reducing absorption Increased absorption capacity and rate; reduced viscosity rate and increasing parasitic energy load for solvent transport Absorption efficiency reduced if Energy efficient removal of water from anhydrous water is present ILs Use of TSILs in membrane contactors

High energy requirement in calcining intermediate regeneration product (CaCO3) High water and solvent loss in spray tower contactor

Co-production of saleable by-products Alternative methods of solvent recovery (titanate cycle) Laboratory-scale spray tower optimization and commercial-scale concept development Process simulation and optimization

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Flue gas to stack

Wash water cooler

Lean solvent cooler

Stripper tower

Absorber tower

Lean solvent

Flue gas cooler

Solvent reboiler

Heat exchanger Rich solvent

Water make-up

Reflux drum

Water wash

Flue gas

CO2 to compression

Reflux condenser

Solvent reclaimer

Steam

Amine reclamation waste

Figure 6.5 Process flow scheme for amine-based CO2 capture from flue gas.

figure is often used a benchmark against which the energy penalty for other processes is compared. Steam and released CO2 exit the top of the stripping tower, where the steam is condensed from the CO2 product stream. Lean solvent from the base of the tower passes through the reclaimer unit where degradation products settle out and is then cooled and cycled back to the absorber. The reclaimer is periodically drained of the amine reclaimer waste (ARW) sediments, which are treated before disposal, e.g., by aerobic or anaerobic digestion, or incinerated in a hazardous waste incinerator or cement kiln. Alternatives to the traditional packed tower configuration have also been investigated for both absorption and stripping, including hollow-fiber membrane contactors (Chapter 8) and solvent microencapsulation systems, discussed below. Due to the low tolerance of amine-based solvents to the presence of SO2 and NO2 in the flue gas, removal of these components to low levels is required ahead of the CO2 capture process, using the techniques described in Chapter 3. A number of amine-based processes have been commercialized, the key features of which are summarized in Table 6.2. The two largest commercial deployment projects to date (2017) in the power generation sector use amine-based capture systems. At SaskPower’s coal-fired Boundary Dam power station near Estevan in Saskatchewan, Canada, Shell’s Cansolvs technology is in use since 2014 to capture 1 Mt-CO2/year, in a project which marked the world’s first large-scale power generation facility covering the whole CCS value chain. CO2 is mostly transported 66 km to the Weyburn-Midale fields for enhanced oil recovery (EOR), with any excess above EOR requirements transported a little over 3 km to SaskPower’s Carbon Storage and Research Centre, which hosts the Petroleum Technology Research Centre administered Aquistore geological storage demonstration project. Significant teething problems were reported with this capture system, causing an

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effective uptime of only 40% during the first year of operation, reportedly due to the impact of flue gas impurities (including fine ash carryover) on the amine solvent. The Petra Nova project, a joint venture between NRG Energy’s Carbon 360 unit and JX Nippon Oil & Gas Exploration of Japan, uses the KEPCO/MHI process, with a 4776 t-CO2/day unit installed in 2016 to capture 1.6 Mt-CO2/year from a B1/3 flue gas slipstream at NRG’s 610 MW W. A. Parish coal-fired power station in Thompsons, TX. The captured CO2 is transported via a 130 km pipeline to Hilcorp’s West Ranch oilfield on the Texas Gulf Coast for EOR. Figure 6.6 shows the layout of the capture facility. The KEPCO/MHI process was selected after a front-end engineering design (FEED) stage which also included an alternative plant design using the Fluor Daniel Econamine FG PlusSM process. Outside the power generation sector, activated MDEA has been in use since 1996 and 2008 to capture 0.9 and 0.7 Mt-CO2/year from natural gas produced at Statoil’s Slepiner and Snøhvit fields in Norway, since 2015 at Shell’s Quest Project (Shell ADIP-X process), where up to 1.2 Mt-CO2/year is captured during hydrogen production from steam methane reforming units at the Scotford bitumen upgrading plant in Alberta, Canada, and since 2016 to capture up to 4 Mt-CO2/year from natural gas at Chevron’s Gorgon Project, in Western Australia. For all these projects CO2 is initially destined for geological storage.

Figure 6.6 KEPCO/MHI capture facility at NRG’s W. A. Parish power plant in Thompsons, TX. Source: Courtesy, NRG Energy Inc.

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Ammonia-based chemical absorption A flue gas CO2 capture process using a chilled slurry of dissolved and suspended ammonium carbonate and ammonium bicarbonate in ammonia has been developed by Alstom Power Systems (now GE Power) and the Electric Power Research Institute (EPRI). The system uses a typical absorber tower configuration, operating at near-freezing conditions (0
10 C), in which cooled flue gas flows upward in countercurrent to the absorbent slurry. The low operating temperature allows high CO2 loading of the solvent slurry and reduces “ammonia slip”—the carryover of entrained ammonia droplets and suspended solids with the clean flue gas exiting the tower. Ammonia slip is further reduced by a cold water wash of the cleaned flue gas, which consists mainly of nitrogen, excess oxygen, and a low residual concentration of CO2. The solvent slurry regenerator operates at temperatures .120 C and pressures . 2 MPa. Ammonia slip on regeneration is also controlled by water washing, yielding a high-pressure CO2 stream with low moisture and ammonia content. This highpressure regeneration has the advantage of reducing the energy requirement for subsequent compression and delivery of the CO2 product stream for storage. The flow scheme of the CAP is shown in Figure 6.7. As part of an extensive development program, proof-of-concept pilot testing at a 15 kt-CO2/year scale demonstrated the capabilities of the technology and was followed by two larger scale pilot projects: a 30 MWe slip-stream test at AEP’s 1.3 GW coal-fired Mountaineer plant in West Virginia (Figure 6.8 and video tour of the plant in Resources), capturing up to 110 kt-CO2/year with storage on-site at the plant in the Mount Simon Sandstone saline aquifer, and a test at Technology Centre Mongstad, located next to Statoil’s Mongstad refinery in Norway, capturing up to 82 kt-CO2/year from the refinery’s cracker unit flue gas or from a new natural gas powered CHP plant (see Augustson et al., 2017). Following successful completion of these validation pilots, two full-scale demonstration projects have been planned: a second stage project capturing 1.5 Mt-CO2/year from a 235 MWe unit at the AEP Mountaineer plant, and a full CCS demonstration, also planned to capture 1.5 Mt-CO2/year from a 330 MWth lignite-fueled power unit at the Turceni Energy Company’s 2 GW power plant, in Gorj County, Romania, with CO2 transported

2-stage cooling

Flue gas cleaning and cooling

Figure 6.7 CAP flow scheme.

CO2 absorber

Flue gas desulfurization

Flue gas wash

CO2 wash Lean AC Heat exchange

Rich ABC

CO2 absorption

Solvent regenerator

Flue gas to stack

CO2 to compression

Reboiler

Solvent regeneration

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50 km for storage in a deep saline aquifer. Unfortunately, both projects have been put on hold, since 2011 and 2012, respectively, due to regulatory and financing uncertainties.

6.2.2 Physical absorption applications As noted above, capture of CO2 by physical absorption relies on the solubility of CO2 in the solvent, which depends on the CO2 partial pressure and temperature of the feed gas. Figure 6.9 illustrates the relative solvent loading of chemical and physical solvents as a function of the partial pressure of the sorbate gas. As shown in Equation (6.25), the solvent loading capacity of physical solvents increases with the partial pressure of the sorbate. Although chemical solvents can

Figure 6.8 CAP installation at AEP’s Mountaineer Plant, West Virginia, USA. Source: Courtesy, GE Power.

Solvent loading

Physical solvent

Chemical solvent

Partial pressure

Figure 6.9 Relative solvent loading of chemical and physical solvents.

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achieve high loading at low partial pressure, physical solvents are favored at highpressure. Physical absorption is therefore typically applied to CO2 separation at high-pressure, such as CO2 recovery from a produced natural gas stream, while chemical absorption is preferred for low-pressure applications, such as CO2 capture from flue gases. Use of physical absorption for CO2 capture from flue gas would require compression of large volumes of gas, the major component being nitrogen, which would subsequently be blown down for release to the atmosphere. The attendant energy penalty would make this process unattractive.

Selexoltprocess The Selexolt process uses a liquid physical solvent to remove acid gas from synthetic or natural gas streams and has been in commercial application since the early 1970s, with well over 50 units currently operating worldwide. The proprietary Selexol solvent was originally developed by Allied-Signal (now Honeywell) in the 1950s and is a DMEPG mixture with the formula [CH3(CH2CH2O)nCH3], where n is 3
9. Table 6.3 shows the relative solubilities of typical gas stream components in the Selexol solvent. Because of the high solubility of water, the partial pressure of Table 6.3 Relative solubilities of sorbates at 25 C (CO2 5 1) Component Hydrogen Methane Ethane Carbon dioxide Propane nButane Carbonyl sulfide nPentane Hydrogen sulfide nHexane nHeptane Water

Selexol solvent

Rectisol solvent (methanol)

Fluor solvent (propylene carbonate)

H2 C1 C2 CO2 C3 nC4 COS

0.013 0.066 0.42 1.00 1.01 2.37 2.30

0.0054 0.051 0.42 1.0 2.35 — 7.06

0.0078 0.038 0.17 1.00 0.51 1.75 3.29

nC5 H2S

5.46 8.82

— 3.29

5.0 7.06

nC6 11.0 nC7 23.7 H2O 730

— — —

13.5 29.2 300

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135

water vapor in the feed gas stream to a Selexol plant must be kept low in order to avoid impairing the CO2 loading capacity of the solvent. Although the solubilities of propane (C3H8) and heavier hydrocarbon components exceed the solubility of CO2, the actual removal rate of these components from a hydrocarbon gas feed stream will depend on the partial pressure, operating temperature, solvent to gas ratio in the absorber, and other operating parameters. Figure 6.10 illustrates the basic Selexol process for CO2 removal from a natural gas stream. Feed gas is mixed with the rich solvent, cooled and separated, and then enters the absorber tower. The separated solvent is regenerated in two or more flash stages; off-gas from the first (HP) flash includes absorbed C1 and C2 and is returned to the absorber tower. CO2 is recovered as off-gas from the second and later flash drums, total CO2 recovery and product purity increasing with subsequent flash stages. The process can be optimized for either trace or bulk removal of acid gases (H2S, COS, and CO2), while the high solubility of heavy hydrocarbon components means that it can also be used for dew point control of hydrocarbon gas to pipeline or LNG feed specifications. The Selexol process has been deployed in the world’s largest operating capture plants in both natural gas processing and power generation sectors. Occidental Petroleum’s Century Plant in Pecos County, TX, in operation since 2010, is the world’s largest capture plant in terms of capture rate, with a capacity to remove 8.4 Mt-CO2/year from high CO2 natural gas. Captured CO2 is transported some 250 km and distributed to a number of Permian Basin oilfields for EOR. At Mississippi Power’s Kemper County Energy facility, in operation since October 2016, the Selexol process is used to capture 3 Mt-CO2/year from syngas at a newbuilt lignite-fueled IGCC power plant, reducing the CO2 emission from the plant by Flue gas to stack CO2 to compression

Absorber tower

Lean solvent

Flue gas Heat exchanger

Sump HP flash LP flash

Figure 6.10 Selexot process scheme.

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B65%. Captured CO2 is transported 100 km to Denbury resources Heidelberg field for EOR, where it replaces the stream previously sourced from Jackson Dome natural CO2 field.

Rectisol process The Rectisol process, using refrigerated methanol as a physical solvent, was initially developed by Lurgi GmbH (now part of Air Liquide SA) and found its first commercial application in 1955 in the purification of coal gasification syngas for ammonia and Fischer
Tropsch liquids production. It has become the dominant process applied worldwide for syngas purification and now purifies 75% of syngas produced globally. The Rectisol process can be configured in many different ways, depending on the types of contaminants to be removed and the required product streams—e.g., whether food-grade CO2 is required. When applied to CO2 capture from a syngas production process after water
gas shift conversion (Section 3.1.2), raw syngas, produced by partial oxidation of the input fuel, is cooled and enters the purification plant where, if necessary, trace components such as HCN and NH can be removed in a cold methanol pre-wash stage. H2S is then removed in an absorber using CO2rich methanol. Regeneration of the H2S-rich solvent takes place in two stages: 1. A medium-pressure flash recovers H2 and CO, which are returned to the syngas stream 2. Hot regeneration using methanol vapor as a stripping gas recovers H2S, which can be fed to a Claus plant for sulfur recovery

Following desulfurization, the raw syngas is water
gas
shifted (Figure 6.11), producing a stream with typically 33% CO2 content. This is cooled and enters the CO2 absorber, where CO2, typically at a partial pressure . 1 MPa, is removed by contact with refrigerated methanol at
10 C to
70 C. Two contacting stages are used, with flash-regenerated methanol in the lower stage to initially reduce CO2 content of the syngas stream to B5%, followed by refrigerated hot-regenerated methanol in the upper stage, further reducing CO2 content to B3%.

Absorber

Heat exchanger

Cooler

Flash regeneration

CO, H2

H2 CO shift conversion

Refrigerant

Syngas

Figure 6.11 Rectisol process for CO2 removal from water
gas
shifted syngas.

CO2

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The largest operating Rectisol application is at the Great Plains synfuel plant, which produces natural gas by gasification of lignite. The Dakota Gasification Company plant has been operating since 1984, and the retrofitted capture process has been capturing 3 Mt-CO2/year since 2000, with CO2 transported 330 km for EOR in the Weyburn-Midale fields in Saskatchewan, Canada.

Fluor Solvent process The Fluor Solvent process was developed in the late 1950s by Fluor and the El Paso Natural Gas Company and was the first physical absorption process for CO2 removal from natural gas. Propylene carbonate (C4H6O3) was chosen as the solvent for this process in view of its high solubility of CO2 relative to methane (Table 6.3), and also for its non-corrosivity, allowing plant fabrication from inexpensive non-alloy steel. The process flow scheme for the Fluor Solvent process is shown in Figure 6.12. CO2 is removed from the natural gas stream in a high-pressure contactor operating at below ambient temperature, and the solvent is regenerated by pressure swing in a series of flash vessels at successively lower pressures. Because of the reactivity of propylene carbonate with CO2 and with water at temperatures . 90 C, operating temperature is limited to a maximum of 65 C, while process performance can be improved by chilling the feed gas stream to about 218 C, to condense C5 1 hydrocarbons and increase the CO2 loading capacity of the solvent. This reduces the solvent circulation rate, leading to lower plant capital and operating costs, but, depending on the water content of the feed gas, may require glycol injection upstream of the absorber to prevent hydrate formation (see Section 9.2). Off-gas from the first flash stage is recycled to reduce methane loss. Energy input to the process is limited to gas recycle compression and solvent circulation pumps, with hydraulic turbines used to recover B50% of the required

CO2 free gas

CO2 to compression

Natural gas

Absorber tower

Lean solvent

HP flash Rich solvent LP flash

Figure 6.12 Fluor SolventSM process scheme for CO2 capture from natural gas.

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recompression energy. Solvent loss is low due to the low vapor pressure of the solvent, eliminating any need for solvent recovery by water washing of the treated gas and CO2 streams.

6.3

Absorption technology RD&D status

Although absorption processes for CO2 capture have over half a century of industrial application, it remains an area of significant ongoing RD&D effort, applied both to the continuous improvement of existing processes and to the development of novel systems aiming for a step-change improvement in the cost-effectiveness of absorption as a capture technology. Many solvents are also being investigated for use in hybrid systems, including both absorption 1 adsorption systems and membranes; these developments are discussed in Chapters 7 and 8. The fundamental challenge, on which most R&D effort is focused, is to reduce the overall process energy requirement, particularly that for solvent regeneration. Early (first generation) amine systems required 3.7 GJ/t-CO2 captured for solvent regeneration, and the current achievable level for amine systems is B2.6 GJ/t-CO2. Research on new mixed solvents, such as bi-phasic amine solvents, has reduced this to B2.0 GJ/t-CO2, and results on catalytic regeneration promise further reduction to B1.1 GJ/t-CO2, the latter results both currently at lab-scale only. Since the thermodynamic minimum work of separation of CO2 from flue gas is , 0.2 GJ/t-CO2, the potential for further breakthrough improvements remains and motivates the extensive global R&D effort in this area.

6.3.1 Improved amine-based systems All of the major suppliers of amine-based systems, summarized in Table 6.1, have ongoing development programs aimed at improving the effectiveness and market competitiveness of their proprietary processes. Areas of research and development to improve the performance of these systems include: G

G

G

G

G

G

Improving solvent formulations and regeneration processes to reduce energy requirement and solvent degradation Sterically hindered amines (such as 2-amino-2-methyl-1-propanol) to increase loading via strong bicarbonate formation Use of catalysts to improve absorption kinetics (e.g., piperazine, CA) and to reduce solvent regeneration energy requirements (e.g., γ-Al2O3) Genetic engineering, e.g., by directed evolution (see Glossary), to produce temperature and alkalinity tolerant CA variants Increasing contact area and reducing pressure drop by modified tower packing Reducing energy requirements by increasing heat integration with the host plant

Absorption capture systems

G

G

139

Producing higher amine concentration with reduced corrosion by using new additives Treatment of amine degradation products

6.3.2 Enzyme catalyzed aqueous carbonate solvent R&D Building on the extensive body of industrial experience in the application of aqueous carbonate systems for CO2 and H2S removal from industrial gases, there has been rapid commercial uptake in the application of CA to improve the performance of this process. A Canadian start-up company, CO2 Solutions, completed 1 t-CO2/day pilot testing followed by a small (8 t-CO2/day, 2500 h) demonstration test in 2015, removing CO2 from coal and natural gas flue gases. A proprietary CA was dissolved in the K2CO3 solvent, with regeneration using hot water at 75
85 C rather than steam. Planning is also in progress for a large-scale pilot to capture CO2 from flue gases at a heavy oil thermal EOR operation in Saskatchewan. The first commercial deployments are in planning, including capturing 30 tCO2/day from a pulp mill with CO2 reused in a greenhouse and at 300 t-CO2/day with CO2 used for EOR. These projects may also include the first carbon capture application of rotating packed bed (RPB) technology, replacing a 370 m3 absorber tower with two 6 m3 RPBs, significantly reducing capital cost. Other focus areas for enzyme-related R&D include engineering and synthesis of CAs (e.g., by directed evolution) with higher thermal stability and prolonged activity, low-cost immobilization methods which maintain high enzyme activity and stability, and development of novel multiphase contacting systems.

6.3.3 Phase-change solvent R&D Bi-phasic liquid solvent R&D A mixed solvent system comprising the tertiary alkanolamine DEEA (diethylethanolamine) and MAPA (N-methyl-1,3-diaminopropane), which has one primary and one secondary amine functional group, was investigated as part of the EU iCap project (see Resources). In a lab-scale pilot, this solvent achieved a one-third reduction in regeneration energy requirement (2.4 GJ/t-CO2) compared to the 30 wt% MEA benchmark (3.6 GJ/t-CO2). The process flow scheme is similar to the basic amine process with thermal regeneration (see Figure 6.5), with the addition of a liquid
liquid separator between two towers. This can be located either before or after the heat exchanger, depending on whether additional heat is required to create the phase separation (TBS). Figure 6.13 illustrates the process for the latter case. An industry scale, 3.5 MWe equivalent, pilot of a bi-phasic solvent developed by IFP Energies Nouvelles (the DMXt process) has been planned as part of the EU-funded OCTAVIUS project. This process, using a dipropil-methyl-xanthine based solvent has one of the lowest reported solvent regeneration requirements, at

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Flue gas to stack

CO2 to compression

Lean solvent

Liquid-liquid separator

CO2 rich phase

Flue gas

Heat exchanger

Stripper tower

Absorber tower

CO2 lean phase

Lean solvent

Solvent reboiler

Rich solvent

Figure 6.13 Simplified flow scheme for bi-phasic solvent capture process.

2.1 GJ/t-CO2. Unfortunately the retrofit of the process at ENEL’s 48 MW Brindisi power plant was too expensive to be funded within the project budget, and the pilot is now on hold.

Precipitating solvent R&D Precipitating solvents are under investigation as part of the ongoing (2014
2017) EU FP7-funded HiPerCap project. As part of its scope on absorption capture, this project will focus on inorganic solvents that can achieve high CO2 loading by precipitating reaction products, while avoiding the problems of emissions and degradation associated with organic solvents. An industrial pilot capturing 1 t-CO2/day has been conducted using a concentrated potassium carbonate precipitating system—the UNO MK3 process developed by CO2CRC—on the GDF-SUEZ Australian Energy operated Hazelwood Power Station in Victoria, Australia, and confirmed low regeneration energy, good environmental performance, and low overall costs. Further work toward large-scale demonstration will include testing the impact of rate promoters such as the amino acid glycine, which has been shown in a lab-scale pilot to give a sixfold increase in absorption rate.

6.3.4 Ionic liquid solvents One of the disadvantages of liquid solvents for gas separation is the loss to the gas stream of solvent, and water in the case of aqueous solutions, due to the vapor pressure of the solvent solution. Ionic liquids (ILs), formed by the melting of certain organic and inorganic salts, have negligible vapor pressure as a result of the strong Coulombic attraction between the constituent ions and could therefore avoid solvent loss.

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141

ILs typically comprise a large organic cation and a smaller organic or inorganic anion, and it is this asymmetry between the cation and anion sizes that reduces the strength of the binding force and results in a low melting point. Properties such as CO2 absorption capacity, viscosity, and thermal stability can be tuned by varying the size and structure, particularly of the cation.

Task-specific ILs By preparing ILs that include ions with specific functional groups, so-called taskspecific ionic liquids (TSILs) can be designed for separation applications. Amine functional groups have been successfully used; capturing CO2 as a carbamate ion in chemical absorption reactions equivalent to Reaction (6.1). A current RD&D focus of work on TSILs is the engineering of new low-cost liquids with high absorption capacity. TSIL molecular structures are readily amenable to modification, so that structure-dependent physical and thermodynamic properties can be readily optimized. TSILs have been investigated in the EU FP7-funded IoLiCAP project (2011
2016), which synthesized and tested the properties (absorption capacity, corrosivity, etc.) of a wide range of ILs. The project also developed improved molecular simulation models to better understand the structural, thermodynamic, and transport properties of ILs, and equation of state models for IL phase behavior in the presence of CO2 and other solvents. The potential to use ILs in liquid membranes (see Chapter 8) as an alternative to conventional column absorption was also investigated, since this technology promises ease of operation as well as lower energy consumption. The main results from the project should be accessible via the project website (see Resources) once published.

Reversible ILs Reversible (also known as switchable or smart) ILs are a class of solvents in which a key property, e.g., CO2 solubility, undergoes a step-change in response to an external stimulus, such as heat, light, or pH. This abrupt property change allows the regeneration method to be engineered into the structure of the solvent, resulting in substantially lower regeneration energy requirements. These novel solvents also offer higher CO2 loading capacity when compared with more traditional solvents, since they can operate as “dual-mode” solvents, absorbing CO2 by both chemical and physical absorption. Ongoing research focuses on design of reversible IL solvents using molecular modeling to optimize the solvent properties for CO2 capture and regeneration, followed by synthesis, characterization, and testing of the chemical and physical properties of the new solvents.

6.3.5 Solvent microencapsulation Many of the limitations of current solvent systems—such as corrosivity, solvent loss due to high vapor pressure, susceptibility to degradation or absorption

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efficiency loss due to the presence of water, oxygen, or other impurities—arise due to the direct contact between the solvent and the flue gas or system hardware. One way to address these challenges is to isolate the solvent by encapsulation within a permeable shell, and two approaches have been proposed to achieve this, as illustrated in Figure 6.14. In the DA approach, patented by Yang et al. (2015), the solvent is vigorously stirred together with silica (SiO2) nanoparticles, B0.3 μm in diameter, that have been fluorinated to make the surface oleophobic. Encapsulated so-called “liquid marbles” are formed (Figure 6.14A), B80 μm in diameter, which flow and behave like a dry powder. The resulting dry solvent, using either MEA or DEA as the encapsulated solvent, showed improved adsorption capacity compared to the free solvent. The low thermal conductance and high infrared albedo of the silica shell made conventional conductive/radiative heating inefficient to achieve the B120 C required for solvent regeneration, and this was achieved by heating the solvent using microwave absorption. Micro-encapsulated carbon sorbents (MECS) take a different approach to encapsulation, using a solid rather than a powder aggregate shell. MECS were first demonstrated by Vericella et al. (2015), who fabricated permeable silicone microcapsules containing K2CO3 solvent together with a pH indicator dye. On absorption, CO2 diffuses through the B30 μm thick high permeability capsule wall and reacts with the solvent to form a bicarbonate precipitate (the Benfield process—see Section 6.1), the drop in pH being indicated by a change in dye color from blue to yellow. Heating to B60 C then redissolves the precipitate releasing CO2 which diffuses out of the microcapsule. Compared to a standard packed tower absorber geometry, the fabricated microcapsules exhibited a 10- to 100-fold increase in surface area per unit solvent volume, and a further enhancement in absorption rate was demonstrated by including Zn-cyclen (Zn-1,4,7,10-tetraazacyclododecane—a CA mimic) with the

(A) Dry alkanolamine (DA)

Oliophobic SiO2 nano-particles

MEA solvent ~3 μm

~80 μm

K2CO3 solvent ~30 μm

~600 μm

CO2 diffusion between nano-particles (B)

Micro encapsulated solvent (MECS)

UV-cured solid silicone shell CO2 diffusion through non-porous shell

Figure 6.14 Schematic structure of (A) dry alkanolamine (DA) and (B) microencapsulated carbon (MECS) sorbents.

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encapsulated solvent. The microcapsules also proved sufficiently robust to use in a fluidized bed type system. Current R&D themes in solvent microencapsulation include techniques to encapsulate a range of solvents, including ILs, and process design aspects, including novel absorber configurations and heat recovery systems. Larger scale and longer term pilot testing is also required to demonstrate sustainable performance, e.g., in the presence of flue gas impurities, but the potential to tailor the capsule material and to encapsulate a wide range of different solvent types opens up a wide field of opportunity to develop improved capture processes.

6.3.6 Sodium hydroxide
based systems Capture of CO2 using chemical absorption by sodium hydroxide is under development for direct air capture and is at the stage of initial deployment for flue gas capture.

Flue gas CO2 capture using sodium hydroxide A flue gas capture process, applying carbonation reactions in Reactions (6.17) and (6.18) to cooled flue gas at 30 C, is under development by Skyonic Inc. in the Skymines process. Few technical details of the process have been released, but the concept shown in Figure 6.15 indicates that hydrogen and chlorine, together with carbon as sodium bicarbonate, in solid form or as a concentrated solution, are the process products. The process also generates other intermediate components; sodium hydroxide is generated in the process by the electrolysis of acidified NaCl brine, and HCl is generated from hydrogen and chlorine products of the brine electrolysis and used to acidify the brine ahead of electrolysis as well as to control pH in the absorption columns. As noted above, pH in the absorption column determines the ratio of carbonate to bicarbonate reactions products. A first deployment of this technology has been implemented at a Capitol Aggregates cement plant in San Antonio, TX. The plant is designed to capture Skymine process Electricity NaCl

H2 NaCl brine electrolysis NaOH

Flue gas

Cl

HCl pH control Clean flue gas

CO2 absorption

Na2CO3, NaHCO3 Other by-products

Figure 6.15 Skymines process schematic.

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75 kt-CO2/year and avoid a further 225 kt-CO2/year by producing carbon-negative Na2CO3. While the process benefits economically from the value of the by-products (H2, Cl, HCl, Na2CO3), the limited markets for these products would be a constraint on large-scale deployment.

Direct air CO2 capture using sodium hydroxide Unlike the capture of CO2 from flue gas or from natural gas processing, which deals with CO2 at partial pressures from B15 kPa to .10 MPa, the direct capture of CO2 from ambient air requires a capture technology that can operate efficiently at a CO2 partial pressure of only B40 Pa. Nevertheless, direct air capture is thermodynamically feasible at an energy cost that could in principle be in the region of 10% of the energy content of fossil fuels. The theoretical minimum energy requirement is determined by the enthalpy of mixing of CO2 in ambient air and is given by: ΔHmix 5 kΤ lnðp=pCO2 Þ

(6.26)

where k is the Boltzmann constant (8.314 J/mol-K) and T is the ambient temperature (K 5  C1 273.15). For typical ambient conditions (25 C 5 298K), kT 5 2.48 kJ/mol, and for CO2 in air at a partial pressure of 40 Pa, ΔHmix 5 19.4 kJ/mol, or 0.44 GJ/t-CO2 (1.62 GJ/t-C). Including the energy required to compress the captured CO2 to B10 MPa for geological storage (at 50% energy efficiency) yields an overall theoretical minimum energy requirement of B1 GJ/t-CO2 (B4 GJ/t-C) for capture from ambient air. Figure 6.16 illustrates an overall process for air capture using NaOH as a solvent. Air is drawn through a contactor where CO2 is captured by the solvent. Physically the contactor could be a packed tower configuration, in which the solvent drips down through packing material designed to maximize contact area, or an empty tower, similar to the familiar evaporative cooling tower of a power plant, with a solvent spray dropping in a co-current (downward) air flow. A 50% capture efficiency is estimated to be achievable with a 1.5 m high packed bed or a 100 m high spray tower. Figure 6.17 shows a 6 m high packed tower under development at the Energy and Environmental Systems Group at the University of Calgary. The tower achieves Air NaOH CO2 to compression

Contactor Ca(OH)2 Causticizer Na2CO3

Slaker

CaO

CaCO3

Figure 6.16 Process concept for air capture using sodium hydroxide.

Calciner

14⬙Ø Light door Sample tap

Pressure tap OUTLET

OUTLET

(3) 15⬙ x 16⬙ outlets

Chevron blade mist eliminator (PP)

14⬙Ø clear viewing access door

68⬙

14⬙Ø Light door 14⬙Ø clear viewing access door FRP liquid distribution trough location

2⬙ body flange 48⬙

48⬙Ø PVC tower Mellapak 250X (S.S.) structured pack 109.8 CU. FT. Depth = 8’–9⬙

Pressure differential gauge 230 W⬙ 240⬙

24⬙Ø Clear viewing access door 16⬙ x 40⬙ air inlet

W” Ø pump out valve 40⬙ Body flange

172⬙

Flowmeter (30–120 GPM) 24⬙Øx 50⬙ LG. Test duct shipped loose

8⬙

Light door

Exhaust fan air flow

Clear level indicator (sight glass) 3⬙Ø flow control valve Pressure gauge (0–30 PSI)

6⬙ Internal drip lip W⬙Ø Liquid fill w/valve 2⬙ Spare capped

54⬙ 37 W⬙

Flat false bottom Price recirculation pump 4⬙ Epoxy-coated steel base

4⬙ (12) 3⬙HLF PVC pipe gussets equally spaced 4⬙ X W⬙ PVC RIB

ELEVATION

4⬙Ø Pump isolation valve 1⬙Ø Drain valve

Figure 6.17 Experimental packed tower for air capture. Source: Courtesy, University of Calgary (photograph) and Advanced Air Technologies Inc. (line drawing).

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a CO2 reduction of B200 ppm with a solvent flow rate of 5 L/s and an air flow speed of 1.25 m/s, at an energy cost of 290 MJ/t-CO2, and has a capture capacity of 15 t-CO2/year per m2 of absorption cross section. An interesting result achieved in these experiments is that the capture performance of the tower falls off only gradually if the solvent supply is interrupted. Intermittent supply of solvent to the tower saves on energy required to pump the solvent, and 85% of the capture performance can be achieved with a 5% solvent pump duty cycle. Evaporative water loss is a potentially significant issue for this type of contactor; a water loss of 20 mol-H2O/mol-CO2 (6.4 t-H2O/t-CO2) was determined for a previous version of a contacting tower (open spray tower rather than packed tower). In the causticizer, NaOH is recovered by the addition of slaked lime (Ca(OH)2) produced by the hydration of lime (CaO) according to Reaction (6.18). The calcium carbonate mud produced in the causticizer is heated in the calciner, driving off water as steam and yielding lime and CO2. Calcining is used on an industrial scale in the production of cement, and a conventional high-efficiency calciner comprises a fluidized bed fired by the combustion of natural gas. The CO2 content of the exhaust gas stream is enhanced as a result of the off-gas from the calcining reaction, and CO2 capture from the exhaust gas stream can then be achieved by any absorption process. The energy efficiency of the process would be enhanced by integrating heat recovery from steam produced in the calciner, as well as recovering low-level heat from the exothermic slaking reaction (ΔH 5
82 kJ/mol). All the elements of such an air capture system are available today as proven technology and are currently applied on an industrial scale in the cement and paper industries. However, the high energy cost for calcining plus the capital cost of the contacting system, which must be added to the cost of a flue gas capture system, means that air capture using such a system cannot be cost-competitive for CCS compared to capture from large sources of emissions. Figure 6.18 illustrates an alternative process scheme that uses the titanate cycle (Section 6.1.1) rather than calcination to regenerate the caustic solvent. Following the spray tower contactor, a first crystallization stage precipitates Na2CO3  10H2O (“deca-crystals”) by cooling the rich solvent to B10 C. Lean solvent is recycled to

Air

Solution reservoir Rich NaOH Water

200 ppm

Heat exchange

Heat exchange

Na2CO3•10H2O “deca-crystals”

Crystallizer

Sodium trititanate

Sodium pentatitanate

Heat recovery

Figure 6.18 Direct air capture process using sodium titanate cycle.

CO2 cooling and compression

Kiln reactor (860°C)

Direct air spray contactor

Crystallizer /leaching

400 ppm

CH4, O2

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147

the spray tower reservoir, while the deca-crystals are conveyed to a second crystallizer/leaching unit. In this unit, operating at 100 C, Na2CO3 is recrystallized in an anhydrous form as a result of the higher temperature and, together with sodium trititanate, is conveyed to a oxycombustion gas-fired reactor, where the trititanate is converted to sodium pentatitanate at 860 C (Reaction (6.22)) and CO2 is released. By using oxycombustion in this reactor, the exhaust gas comprises CO2 plus steam; cooling to 25 C condenses the steam to produce makeup water, while the pure CO2 is compressed for transportation and storage. After cooling, the pentatitanate is leached in the crystallizer and leaching unit, regenerating NaOH and sodium trititanate and completing the titanate cycle. The NaOH is recycled to the spray tower reservoir. Further research on this process will focus on improving the kinetics of the absorption and regeneration steps, optimizing overall system energy efficiency, and the design of a 1 Mt-CO2/year air capture unit. A contacting system of this capacity could take the form of a segmented vertical slab, as illustrated in Figure 6.19. Prevailing winds, assisted by a fan wall, would sustain a horizontal air flow of 2
5 m/s (7
18 km/h) while the solvent falls though a packed wall with vertically oriented packing plates, optimized to maximize liquid hold-up under intermittent flow conditions. Solvent supply would be switched sequentially between slab sections, allowing intermittent wetting of individual sections with continuous pump operation. A 1 Mt-CO2/year air capture unit with a capture capacity of 20 t-CO2/ m2-year would require a 10 m high contactor slab of 5 km length. The achievable cost per tonne of CO2 captured for such a system has been estimated to exceed $300/t-CO2, which will not be competitive with CO2 capture from power plants. However, it does provide an additional option for reducing the atmospheric CO2 inventory that may become relevant in some stabilization scenarios where negative future emissions are necessary, although here too it would have to compete with biomass-based CCS solutions.

Figure 6.19 Conceptual design of intermittently wetted cross-flow air capture contactor. Source: Courtesy, Eric Au, University of Calgary.

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6.4 References and resources 6.4.1 References Augustson, O., Baburao, B., Dube, S., Bedell, S., Strunz, P., Balfe, M., Stallamm, O., 2017. Chilled ammonia process scale-up and lessons learned. Energy Procedia. 114, 5593
5615. Barchas, R., Davis, R., 1992. The Kerr-McGee/ABB Lummus Crest Technology for the recovery of CO2 from stack gases. Energy Convers. Manage. 33, 333
340. Budzianowski, W.M., 2016. Explorative analysis of advanced solvent processes for energy efficient carbon dioxide capture by gas
liquid absorption. Int. J. Greenhouse Gas Control. 49, 108
120. Fradette, L., Lefebvre, S., Carley, J., 2017. Demonstration results of enzyme-accelerated CO2 capture. Energy Procedia. 114, 1100
1109. Hanak, D.P., Biliyok, C., Manovic, V., 2015. Rate-based model development, validation and analysis of chilled ammonia process as an alternative CO2 capture technology for coalfired power plants. Int. J. Greenhouse Gas Control. 34, 52
62. Idem, R., et al., 2015. Practical experience in post-combustion CO2 capture using reactive solvents in large pilot and demonstration plants. Int. J. Greenhouse Gas Control. 40, 6
25. Keith, D.W., Ha-Duong, M., Stolaroff, J.K., 2006. Climate strategy with CO2 capture from the air. Climate Change. 74, 17
45. Liang, Z., et al., 2015. Recent progress and new developments in post-combustion carboncapture technology with amine based solvents. Int. J. Greenhouse Gas Control. 40, 26
54. Mimura, T., et al., 2003. Recent developments in flue gas CO2 recovery technology. Proceedings of the 6th International Conference on Greenhouse Gas Control Technologies. Elsevier Science Ltd, Oxford, UK. Miyamoto, O., et al., 2017. KM CDR Process project update and the new novel solvent development. Energy Procedia. 114, 5616
5623. Mumford, K.A., Wu, Y., Smith, K.H., Stevens, G.W., 2015. Review of solvent based carbondioxide capture technologies. Front. Chem. Sci. Eng. 9, 125
141. Peeters, A.N.M., Faaij, A.P.P., Turkenburg, W.C., 2007. Techno-economic analysis of natural gas combined cycles with post-combustion CO2 absorption, including a detailed evaluation of the development potential. Int. J. Greenhouse Gas Control. 1, 396
417. Rao, A.B., Rubin, E.S., 2002. A technical, economic and environmental assessment of amine-based CO2 capture technology for power plant greenhouse gas control. Environ. Sci. Technol. 36, 4467
4475. Reddy, S., Yonkoski, J., Rode, H., Irons, R., Albrecht, W., 2017. Fluor’s Econamine FG PlusSM completes test program at Uniper’s Wilhelmshaven coal power plant. Energy Procedia. 114, 5816
5825. Russo, M.E., Olivieri, G., Marzocchella, A., Salatino, P., Caramuscio, P., Cavaleiro, C., 2013. Post-combustion carbon capture mediated by carbonic anhydrase. Sep. Purif. Technol. 107, 331
339. Salmon, S., House, A., 2015. Enzyme-catalyzed solvents for CO2 separation. In: Shi, F., Moreeale, B. (Eds.), Novel Materials for Carbon Dioxide Mitigation Technology. Elsevier B.V., Amsterdam. Sanchez-Fernandez, E., de Miguel Mercader, F., Misiak, K., van der Ham, L., Linders, M., Goetheer, E., 2013. New process concepts for CO2 capture based on precipitating amino acids. Energy Procedia. 37, 1160
1171.

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Vericella, J.J., et al., 2015. Encapsulated liquid sorbents for carbon dioxide capture. Nat. Commun. 6, 6124. Wang, X., Li, B., 2015. Phase-change solvents for CO2 capture. In: Shi, F., Morreale, B. (Eds.), Novel Materials for Carbon Dioxide Mitigation Technology. Elsevier B.V., Amsterdam. Yang, J., Tan, H.Y., Low, Q.X., Binks, B.P., Chin, J.M., 2015. CO2 capture by dry alkanolamines and an efficient microwave regeneration process. J. Mater. Chem. A. 3, 6440.

6.4.2 Resources AEP Mountaineer Power Plant (video tour of the CCS pilot facility): www.youtube.com/ watch?v51p4vBl2abak Alstom Power Systems (chilled ammonia process): alstomenergy.gepower.com/microsites/ power/products-services/coal-and-oil-power Carbon Clean Solvents Ltd. (postcombustion capture solvent development): www.carboncleansolutions.com Carbon Engineering Ltd. (commercializing direct air capture): www.carbonengineering.com CO2 Solutions (enzyme accelerated amine solvents): www.co2solutions.com Fluor Econamine FG PlusSM process: www.fluor.com/econamine HiPerCap (EU research project including enzyme catalyzed absorption, precipitating solvents and strong bicarbonate forming hindered amine solvents): www.sintef.no/hipercap iCAP (Bi-phasic solvent research project): http://cordis.europa.eu/result/rcn/156228_en.html IEAGHG 3rd Post-Combustion Capture Conference, 2015 (Technical program and papers): www.ieaghg.org/member/52-conferences/pccc/470-3rd-post-combustion-captureconference IFPEN (DMXt bi-phasic solvent development): www.ifpenergiesnouvelles.com/Researchthemes/Responsible-oil-and-gas/CO2-capture-and-geological-storage IoLiCAP (Ionic Liquid research project): www.iolicap.eu IoLiTec Ionic Liquids Technologies GmbH (commercializing ionic liquid technologies): www.iolitec.de/en ION Engineering (developing absorption-based captsure technology): www.ion-engineering. com Powerspan (ECO2s chilled ammonia capture process): www.powerspan.com Shell Cansolvs process: www.shell.com/business-customers/global-solutions/shell-cansolvgas-absorption-solutions.html Siemens PostCapt (amino acid salt based capture process): www.energy.siemens.com/hq/en/ fossil-power-generation/power-plants/carbon-capture-solutions/post-combustion-carboncapture/ Skymines: www.skyonic.com/technologies/skymine UK CCS Research Centre Pilot-scale Advanced Capture Technology (PACT) (specialist R&D facilities for carbon capture technology research): www.pact.ac.uk US DOE National Energy Technology Laboratory (NETL) (solvent research program): www. netl.doe.gov/research/coal/carbon-capture/post-combustion

Adsorption capture systems

7

In contrast to absorption, in which the absorbed component (the sorbate) enters into the bulk of the solvent and forms a solution, adsorbed atoms or molecules (known as adparticles) remain on the surface of the sorbent. Similar to absorption, however, the bonding of the sorbate to the surface may be through either a chemical bond (chemical adsorption or chemisorption) or a weaker physical attractive force (physical adsorption or physisorption). Gas separation or purification based on adsorption has a history of industrial application as long as that for absorption-based technologies, having been initially driven primarily by air purification applications. Adsorption processes using solid sorbents have a number of potential advantages when compared to absorption into liquid solvents, including a very wide range of operating temperatures, a lack of liquid waste streams, and in many cases solid wastes that are environmentally benign and pose few problems for disposal. A rapid expansion in the application of adsorption as a gas separation technology has occurred in the past decades, due in part to the development of new sorbent materials, and a diverse range of sorbents is now available or under development for CO2 separation. These sorbents can be combined with a broad spectrum of process options, including steady-state and cyclic processes, yielding a very fertile field for performance optimization and innovation.

7.1

Physical and chemical fundamentals

The most important characteristic of a sorbent is the quantity of sorbate that a given quantity of sorbent can hold, at the relevant operating temperatures and pressures. For applications such as CCS that require separation of one specific component from a mixed feed stream, the selectivity of the sorbent for that component is equally important and is determined by the relative adsorptive rates and capacities of the sorbent for the various components in the feed.

7.1.1 Adsorption thermodynamics The process of adsorption is described by the Langmuir adsorption equation, or Langmuir isotherm, which can be derived from a simple model of the equilibrium between adsorption and desorption. For an adparticle of mass m (kg), at pressure P

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00007-6 © 2017 Elsevier Inc. All rights reserved.

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(Pa), the kinetic theory of gases gives the frequency of collisions, ν (s21), of the particle with the containing surface as: ν 5 P=ð2πmkTÞ1=2

(7.1)

where k is the Boltzmann constant (J/K) and T is the absolute temperature (K). If θ is the fraction of adsorption sites that are occupied, and α is the probability of a particle sticking to the surface during any single collision, then the rate of adsorption (A) per unit surface area will be: A 5 ανð1  θÞ

(7.2)

The rate of desorption, B, will be given by: B 5 βθeQ=RT

(7.3)

where β is the rate constant for desorption, Q is the activation energy for desorption, which will be equal to the heat of adsorption (2ΔHabs), and R is the gas constant. At equilibrium, the rates of adsorption and desorption are equal, giving: ανð1  θÞ 5 βθeQ=RT

(7.4)

which can be solved to give the equilibrium coverage θeq: θeq 5 KP=ð1 1 KPÞ

(7.5)

where K 5 αeQ=RT=βð2πmkTÞ1=2

(7.6)

For an n-component system, the equilibrium surface coverage of component i is given by: θeq;i 5 Ki Pi 1 1

n X

! K j Pj

(7.7)

j51

Adsorption from a multicomponent feed is thus a competitive process, since the equilibrium surface coverage of one component will be reduced as the summation in the denominator of Equation (7.7) is increased by the adsorptivity of other components. The general form of the Langmuir isotherm is illustrated in Figure 7.1 for two different temperatures. The temperature dependence of the Langmuir constant is K B eQ/RTT21/2. Since physical adsorption is always exothermic (i.e., ΔHabs is

Adsorption capture systems

153

θeq

TL TH > TL

Equilibrium surface coverage

TH

Pressure

Figure 7.1 Langmuir adsorption isotherms versus temperature and pressure.

Sorbent loading (mol/kg)

TL

TSA working capacity

ΔTSA

ΔPSA TH

PSA working capacity

PL

Pressure

PH

Figure 7.2 Sorbent working capacity for TSA and PSA.

negative), Q in Equation (7.3) is always positive and, as a result, K decreases rapidly with increasing temperature, as shown by the two adsorption isotherms in the figure. The temperature and pressure dependence of θeq are exploited as the basis of the two main adsorption-based gas separation processes: temperature swing adsorption (TSA) and pressure swing adsorption (PSA). In their simplest form, these processes rely on the preferential adsorption of one gas component from a mixed feed stream at a certain operating pressure and temperature (PH, TL), followed by desorption of the adsorbed component at either a reduced pressure or an increased temperature (PL, TH) (or both in the case of PSA and TSA). The differential adsorptive capacity of the sorbent between PH and PL, or TL and TH, is called the working capacity (Δ) of the sorbent, expressed as mol/mol or mol/kg of sorbent (Figure 7.2).

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Recent work on metalorganic frameworks (MOFs) has revealed strikingly different forms of adsorption isotherms compared to the classical Langmuir type illustrated, when CO2 adsorption induces dynamic changes in the crystal structure of the MOF or “cooperative” adsorption behavior occurs between adjacent functionalized sites. These developments are further discussed in Section 7.2. Figure 7.2 shows the ideal case in which adsorption and desorption follow exactly the same isotherm. In practice, as shown in Figure 7.3, many sorbent/sorbate combinations exhibit hysteresis, with the desorption isotherm falling above the adsorption isotherm as a result of capillary condensation. As sorbate loading increases, multiple layers of adparticles may bridge across small pores or pore throats in the sorbent material and condense into lower energy configurations (the process is illustrated in Figure 8.4 as it occurs in porous membranes). This increases the energy required to achieve full desorption, and the sorbent would need to be drawn down to a pressure below PL in order to achieve the full working capacity shown in Figure 7.2. For a given mass of sorbent (mabs) of working capacity Δ, applied in an adsorption cycle of total duration tc, the rate of production of the sorbate-rich product under ideal conditions is: q 5 mabs Δ=tc

(7.8)

For a given process throughput rate, the sorbent mass and related plant size and cost are therefore minimized by shortening the duration of the cycle. Rapid cycling is also desirable since release of the heat of adsorption results in heating of the sorbent bed during adsorption. Excessive heating will reduce the capacity of the 9

Sorbent loading (mol/kg)

8 Activated carbon 2.2 mol/kg

7 6

Zeolite-13X 1.7 mol/kg

5 4

Natural zeolite 2.3 mol/kg

3 2 1

Activated C adsorption

Activated C desorption

Zeolite-13X adsorption

Zeolite-13X desorption

Natural zeolite adsorption

Natural zeolite desorption

0 0.0

0.5

1.0 1.5 2.0 Equilibrium pressure (MPa)

2.5

3.0

Figure 7.3 Adsorptiondesorption isotherms of activated carbon, zeolite 13X, and natural zeolite at 25 C.

Adsorption capture systems

155

sorbent bed and conversely, if the bed is allowed to cool before pressure swing desorption occurs, the increase in adsorptive capacity of the sorbent as the temperature falls will reduce the working capacity of the bed. One approach to mitigate temperature fluctuations—incorporating phase-change materials (PCMs) into the sorbent bed—is discussed in Section 7.2. In general, TSA cycles require relatively longer heating and cooling times, leading to large sorbent beds for a given throughput, while PSA cycles can be faster and employ smaller beds, since pressurization and depressurization can be achieved more rapidly.

Sorptiondesorption characteristics The desired properties of sorbents for CO2 separation are summarized in Table 7.1, and the adsorptiondesorption isotherms for three low-temperature CO2 sorbents (activated carbon, natural zeolite, and zeolite 13X) at 25 C are shown in Figure 7.3, which illustrate the desired properties listed in the table. Activated carbon has the highest CO2 adsorption across most of the pressure range, reaching 8 mol/kg at 2 MPa, as well as the steepest adsorption isotherm. However, the desorption isotherm shows a high degree of hysteresis, reducing the working capacity over the pressure range shown to B2.2 mol/kg. Zeolite 13X shows an intermediate adsorption capacity, with very low hysteresis, but the shallow gradient of the isotherm results in a lower working capacity of 1.7 mol/kg. Natural zeolite has the lowest adsorption capacity, little more than half that of activated carbon at 2 MPa, but the steeper isotherm and relatively low hysteresis result Table 7.1 Desired properties of CO2 sorbents Property

Description

Preferential CO2 absorption Low heat of adsorption

High selectivity for CO2 relative to other CCS relevant gases (N2, CO, CH4) is essential for an efficient adsorption/desorption cycle Low heat of adsorption ensures that the drop of pressure or increase in temperature required in the desorption stage does not result in a high energy penalty Increased working capacity reduces the volume of sorbent required for a given throughput, reducing sorbent bed and related equipment size, capital costs, and energy requirements Hysteresis of the adsorption isotherm results in an increased pressure drop to achieve the same sorbent working capacity, increasing the energy penalty A sorbent with a steep adsorption isotherm delivers a given working capacity with the lowest pressure or temperature swing, and therefore the lowest energy penalty

High sorbent working capacity Low adsorption hysteresis Steep adsorption isotherm

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in a working capacity over this pressure range of 2.3 mol/kg, marginally higher than activated carbon.

Chemical and physical sorbents Due to the weaker binding forces and resulting lower heat of adsorption, physical sorbents tend to find application at low temperatures, while chemical sorbents, with higher heats of adsorption, are able to sustain high capacity at higher temperatures. The division between physical and chemical sorbents is therefore also in general a division between low and high operating temperatures, although there are exceptions such as surface-modified porous media. A wide variety of sorbents can be used for low-temperature CO2 capture, including those summarized in Table 7.2. Table 7.2 Low-temperature CO2 sorbents Sorbent

Description

Activated alumina

Non-reactive synthetic amorphous sorbents with low heats of adsorption produced from aluminum trihydrate. The sorbent can be a beaded material or powder, and surface areas can be controlled during manufacturing to tailor the sorbent to various applications Carbonaceous crystalline sorbents are available with a wide range of properties, depending on the raw material and activation method. Activated carbons are used in a wide range of purification processes, from purification of drinking water to various petrochemical applications Ionic polymers typically prepared as macroporous beads, in which either the anion or the cation is bound to the resin structure while the counterion is free. Ions (e.g., CO322) with the same charge as the free counterion can be exchanged from a solute into an anion exchange resin Networks of metal ions or metal ion clusters connected into an extended nanoporous structure by organic linkers. Selection of different combinations of metal ion 1 linker allows control of the MOF pore size and shape, enabling tuning of sorption capacity and selectivity Silica, carbon- or polymer-based meso-, micro-, or nanoporous media with high specific areas, modified by the incorporation of functional groups such as amines and related organic compounds Naturally occurring and synthetic microporous minerals composed of hydrated sodium, potassium, calcium, or magnesium aluminosilicate which are able to trap adparticles within their open crystal structure

Activated carbon

Ion-exchange resins

MOFs

Surface-modified porous media Zeolites

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Table 7.3 High-temperature CO2 sorbents Sorbent

Description

Metal oxides (e.g., CaO)

High-temperature (6001000 C) chemical sorbents, transformed to carbonates and bicarbonates and regenerated by calcining at temperatures of B900 C Naturally occurring anionic clays that become CO2 sorbents in the temperature range B200400 C, displaying superior stability than CaO but lower capacity and slower reaction kinetics Mid- to high-temperature (600750 C) chemical sorbent. Capacity can be significantly increased by adding potassium carbonate (K2CO3)

Hydrotalcites

Lithium zirconate (Li2ZrO3)

These low-temperature sorbents are typically applied at temperatures from ambient up to B100 C, in a few cases up to a few hundred degrees, since their capacity drops to very low levels at higher temperatures. A range of sorbents has also been developed with high capacities at the operating temperatures typical of hot flue gas applications (400600 C). Table 7.3 summarizes a number of these high-temperature sorbents, while further novel materials under development are described in Section 7.2.

7.1.2 Chemical sorbents Metal oxide sorbents Several of the absorbents described in Chapter 6 have also been applied in the solid state as chemical adsorbents, the most common examples being the carbonation of metal oxides, such as calcium, sodium, and potassium oxide, as well as the further carbonation to produce bicarbonates: CaOðsÞ 1 CO2ðgÞ 2CaCO3ðsÞ Na2 OðsÞ 1 CO2ðgÞ 2Na2 CO3ðsÞ

(7.9) (7.10)

The high temperatures required for the calcination step make these sorbents particularly suited to flue gas or syngas processes, typically taking place at 400600 C. However, at temperatures above 533 C (the Tammann temperature for CaCO3) sintering occurs, leading to loss of adsorption capacity over repeated cycles. To address this problem, CaO-based sorbents are being developed, the most promising being certain calcium aluminates—solid solutions of CaO and Al2O3.

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Alkali metal carbonate sorbents The carbonates of alkali metals, such as Al, K, and Na, react reversibly with CO2 and water to form bicarbonates, the carbonate being regenerated by heating. The reaction of sodium carbonate (Na2CO3) to form sodium bicarbonate (Na2HCO3) or Wegscheider’s salt (Na2CO3  3NaHCO3) has been investigated for CO2 capture from post-combustion flue gases. Carbonation and regeneration occur as a result of the following reactions: Na2 CO3 1 CO2 1 H2 O22NaHCO3

(7.11)

Na2 CO3 1 0:6CO2 1 0:6H2 O20:4ðNa2 CO3  3NaHCO3 Þ

(7.12)

The carbonation reactions occur in the temperature range 6070 C and are exothermic, with a heat of absorption of approximately ΔHabs 5 2136 kJ/mol-CO2 (3.1 GJ/t-CO2). Regeneration of the sorbent is then achieved in the reverse reactions in the temperature range 120200 C. The disadvantages of these sorbents are the relatively low loading capacity (311 wt%) and the high desorption energy requirement.

Supported amine sorbents Amines and related organic absorbents have also been applied as adsorbents, by attaching the functional groups onto the surface of high-specific-area solids such as meso- or microporous silica, alumina, or polymer-based materials. The rate and efficiency of adsorption is increased as a result of the high-surfacearea of the supporting material, which allows easy access of CO2 to the amine or other functional groups. Sorbent loading significantly higher than aqueous amine solutions and a regeneration energy roughly 1/3 of the 30% monoethanolamine benchmark have also been reported for functionalized porous sorbents. Oxidative degradation and loss of the sorbent by evaporation are minimized as a result of the surface binding, while the operational problems typical of aqueous solvent systems, notably corrosion, foaming, and contaminated wastewater, are eliminated in the dry gassolid system. For industrial application it is advantageous to shape these sorbents as pellets rather than in powder form, and pellet fabrication methods are an active R&D area. Solid amine sorbents, using polyethyleneimine bonded to acrylic-based polymer beads, have been used since the early 1990s for CO2 removal in space shuttle lifesupport systems, with regeneration by vacuum swing desorption, and have a potential application in direct air capture (DAC) (see Section 7.2).

Hydrotalcites Hydrotalcites (HTCs) are a class of high-temperature chemical sorbents that have been widely investigated for application in sorption-enhanced reactions (Section 7.2.2). Also known as layered double hydroxides or Feitknecht

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compounds, HTCs are a family of naturally occurring anionic clays with the general formula: M21 12x M31 x ðOHÞ2 ðAn2 Þx=n  mH2 O Here M21 and M31 are divalent (e.g., Mg, Ni, Zn, Cu, Mn) and trivalent (e.g., Al, Fe, Cr) metal ions, most commonly magnesium and aluminum, respectively, 2 22 22 2 An2 is an anion (most commonly CO22 3 , but also SO4 , NO3 , Cl , OH ), and the value of x is 0.10.5. The metal ions are held in an octahedrally coordinated hydroxide layer, similar to the mineral brucite, while the anions and water of hydration occur in an anionic interlayer (see Figure 7.4). The net positive charge of the metal ion layer is compensated by the net negative charge of the anionwater interlayer. The mineral hydrotalcite is the most common of the class of HTCs and has the formula: Mg0:75 Al0:25 ðOHÞ2 ðCO3 Þ0:125  0:5H2 O The thermal decomposition (calcining) of HTC is a complex three-stage process, starting in the temperature range from ambient up to B300 C, with the dehydration of water molecules held in the anionwater interlayer. At temperatures up to 700 C, this is followed by dehydroxylation, in which OH groups plus oxygen from the metal ion layer are released as H2O, while two oxygen atoms from a carbonate ion are included into the metal ion layer. This leads to the start of decarbonation and the release of CO2. Up to about 500 C, the so-called HTC memory effect ensures that the layered structure is restored on rehydration, either in a carbonate solution or by steam in the presence of CO2. Above 700 C, decarbonation of the interlayer is completed, resulting in the final decomposition products MgO and MgAl2O4 in the case of mineral HTC. The calcining process is accompanied by a rapid increase in the specific surface area as the progressive loss of the anionwater causes the clay layers to separate. The resulting high density of strong basic sites on the layer surfaces make HTCs Brucite Mg(OH)2 octahedra Mg2+ cation OH− anion

Interlayer anion, e.g., CO32− H2O molecule

Figure 7.4 Layered structure of hydrotalcite.

Layered hydrotalcite structure

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effective as high-temperature CO2 sorbents, with the optimum calcination temperature for a given HTC being determined by the balance between surface area and active site density. The CO2 loading capacity of HTC can be significantly increased by impregnating (or promoting) the mineral with 1020 wt% of potassium carbonate (K2CO3), however, loading capacity and carbonation and decarbonation rates remain inferior to CaO. It is mainly in the area of sorbent stability that HTCs performance exceeds that of the simpler metal oxides, although ongoing R&D efforts.

7.1.3 Physical sorbents Two classes of physical sorbents that have received considerable attention for postcombustion CO2 capture are zeolites and MOFs.

Zeolites Zeolites (from the Greek for “boiling stone” due to their release of water on heating) are naturally occurring and synthetic microporous minerals composed of hydrated sodium, potassium, calcium, or magnesium aluminosilicate. The open crystal structure of zeolites incorporates cages of various sizes within which adparticles can be trapped. This is illustrated in Figure 7.5, which shows the structure and structural elements of zeolites Sodalite, Linde A, and Faujasite. Zeolites have high adsorption capacity at low temperatures (,100 C) and partial pressures (,1 bar CO2) and exhibit very rapid adsorption, in many cases reaching equilibrium in a few minutes. A range of different structures, and trap sizes, can be synthesized at low cost (zeolite 13X and 5A are the most commonly investigated), and their CO2 selectivity and adsorption capacity can be improved by surface

SOD

Double 6-ring (DSR)

LTA

O–Si–O structural element 145 degrees bond angle

FAU

Figure 7.5 Crystal structure and trapping cages in zeolites.

β-cage (SOD or Sodalite cage)

α-cage (Super cage)

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treatment, e.g., by amine impregnation. The main disadvantage is their structural instability in the presence of water.

Metalorganic frameworks MOFs are crystalline nanoporous materials composed of networks of metal ions or clusters of metal ions connected into extended nanoporous structures by organic linkers—known as ligands. A simple cubic MOF structure is illustrated in Figure 7.6. Selection of different metal ion 1 ligand combinations allows the pore size and shape of the framework to be controlled, enabling tuning of sorption capacity and selectivity, so that this class of materials has considerable potential for efficient CO2 capture. Zeolitic imidazolate frameworks (ZIFs), are a type of MOF composed of transition metal ions (e.g., Fe, Co, Cu, Zn) connected by imidazolate (C3H4N2) linkers. Because the metalimidazolemetal angle is very close to the SiOSi angle of 145 degrees, as shown in Figure 7.5, ZIFs form lattice structures that are topologically isomorphic to zeolites. As well as being studied as selective gas sorbents, ZIFs have also been investigated for applications as reaction catalysts, and in a hybrid absorption (glycol solvent) plus adsorption (ZIF sorbent) system. As CO2 sorbents, MOFs have high sorption capacity at low temperatures and high CO2 partial pressure, but generally perform less well at high-temperature, low partial pressure and in the presence of impurities. In particular, water can disrupt the MOF lattice structure by displacing the ligands. MOFs have yet to progress beyond laboratory studies, and areas of current R&D focus are summarized below.

Joint, metal ion, oxide, or (poly)metallic cluster

Link organic ligand

Figure 7.6 Example of simple cubic MOF structure.

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Adsorption process configurations and operating modes

A variety of different physical configurations and operating modes can be used in the sorptiondesorption process, the main distinctions being between fixed and moving sorbent beds, and between temperature and pressure swing sorbent regeneration.

7.2.1 Fixed bed adsorption systems In simple fixed bed systems the sorbent is held in a vessel with feed gas entering at one end and light product, from which the sorbate has been removed, produced at the other. When a bed is first put into feed mode, transfer of the sorbate from the feed gas to the sorbent starts at the feed end of the bed. Figure 7.7 illustrates the progressive movement of this mass transfer zone through a fixed bed. Feed Mass transfer zone Regenerated sorbent Sorbate concentration ahead of mass transfer zone C = CP

MTZ

CP

CO

MTZ

MTZ

Saturated sorbent Sorbate concentration behind mass transfer zone C = CO

MTZ

CO Sorbate concentration in bed effluent CP

Breakthrough

Time

Figure 7.7 Movement of the mass transfer zone through a fixed sorbent bed.

The figure shows that throughout the adsorption period, only a small part of the sorbent inventory is actively adsorbing, while the majority of the sorbent is either fully loaded, and therefore awaiting regeneration, or not yet contacted by the sorbate. The release of the heat of adsorption within the localized mass transfer zone also means that heat transfer requires careful attention in fixed bed design. This is needed in order to avoid overheating of the sorbent, leading to a reduction in carrying capacity, or to a waste of the liberated heat, which would increase the energy penalty for regeneration.

7.2.2 Moving bed adsorption systems Moving bed processes overcome these difficulties, since each parcel of sorbent can be more promptly exported from the adsorption bed for regeneration once it has

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been fully loaded, while mass transfer between sorption and desorption zones provides an extra degree of freedom for overall heat management within the process. The moving bed concept was initially patented in the 1920s as a method of separating components from coal gasification syngas and was renamed hypersorption when renewed interest in the late 1940s led to the construction of a number of commercial moving bed units. As illustrated in Figure 7.8, the moving bed or hypersorption process is functionally equivalent to a distillation tower, and one of the feature of the process is that the flexible operating conditions—temperature, pressure, and sorbent circulation rate—can be tuned to perform sharp separations. Feed is introduced into the middle of the column and contacts sorbent, which is moving down under gravity. More adsorbing components in the feed move down with the sorbent, while less adsorbing components move up and exit the top of the column. The decreasing temperature toward the top of the column, controlled by cooling the circulating regenerated sorbent, increases the adsorptive capacity of the sorbent and improves separation. Heat is provided to the bottom of the column by a heated reflux of the heavy product, equivalent to a distillation column reboiler. The increasing temperature toward the bottom of the column progressively releases the sorbate, with the potential for recovery of intermediate as well as heavy product streams. Reflux of product side streams back into the hypersorption columns can be used to achieve increased purity of these products, while multistage hypersorption, using two or more such columns in series, can also be used for separating multiple feed components. A pilot-scale (5 t-CO2/day) moving bed post-combustion capture system, using amine-impregnated porous sorbent particles, has been demonstrated by Kawasaki Heavy Industries (see Okumara et al., 2017). This system has the advantage of

Figure 7.8 Schematic of hypersorption gas separation unit.

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using low-temperature (60 C) waste steam for regeneration, and pilot results indicate a low capture energy penalty of 1.3 GJ/t-CO2. An alternative form of moving bed that has been proposed for carbon capture applications is the rotating packed bed (see Gupta and Ghosh, 2015). In this configuration, circular sorbent disks rotate between an adsorption chamber where they are exposed to flue gases and a desorption chamber where the sorbent is regenerated under a pressuretemperature swing. Conceptual studies of this system, using activated carbon and zeolite 13X as sorbents and configured for post-combustion capture from a 500 MW power plant, indicated an energy penalty and cost of carbon avoided that were significantly less than other capture technologies.

Simulated moving beds An intermediate step between fixed and moving beds is a simulated moving bed, in which sorbent in a fixed bed is cycled through the flows, temperatures, and pressures as experienced by a parcel of sorbent circulating in a moving bed process. This is illustrated in Figure 7.9, where a moving bed system is broken into four process steps. The fixed bed here undergoes the same adsorptionregeneration process experienced by a parcel of sorbent moving through the hypersorption column: Zone A B C D

Process step Sorbent cooling by chilled light product reflux Feed and light product recovery Heavy product recovery Further heavy product recovery by temperature swing

This scheme is conceptually identical to the cyclic schemes described later in this section, where each individual fully loaded bed is taken through a sequence of regeneration steps and then rejoins the cascade of adsorbing beds. A moving bed can also be simulated using a long fixed bed by sequentially moving the inlet and outlet feed and regeneration points along the bed. This technique Desorbent (or Purge) Desorbent

Heavy product D

A

Light product

B

Feed C Solid sorbent flow

D

A

Heavy product Desorbent flow

Light product

Figure 7.9 Simulated moving bed using cascaded fixed beds.

C Bed switching direction B

Feed

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is applied to small-scale fractionation for chemical analysis and is known as moving port chromatography.

Fluidized beds Fluidized beds are the most common form of moving bed adsorber and have been developed to a high state of refinement due to their widespread application in many industrial processes, including power generation combustion and gasification, as described in Section 3.1. Figure 7.10 illustrates a state-of-the-art fluidized bed absorber. Fluidized beds also introduce additional technical requirements, including the need for the sorbent particles to resist attrition, and for equipment to circulate sorbent and to remove attrition products.

Chemical looping In chemical looping systems, similar to the fluidized bed configuration discussed above, the sorbent is circulated between separate reactors in which the chemical adsorption and desorption reactions take place. The concept is illustrated in Figure 7.11, which shows schematically a chemical looping system for postcombustion capture. The chemical looping concept has also been extensively investigated and pilot tested for use at the combustion stage, as a variant of oxyfueling, and chemical looping combustion (CLC) has emerged over the last decade as a leading clean coal technology. In CLC, a metal oxide sorbent carries oxygen to a fuel reactor where Sorbate depleted feed

Fluidized bed adsorber

Adsorption section

Feed Cooling medium Fluidized sorbent conveyer

Condenser Heating element

Recovered sorbate

Heating steam

Desorption section Stripping gas (Nitrogen, air)

Carrier air

Figure 7.10 Fluidized adsorption bed configuration.

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Figure 7.11 Schematic chemical looping system for post-combustion capture.

combustion takes place; the reduced oxygen carrier is then conveyed to an air reactor where it is regenerated (oxidized in air), closing the loop. Chemical looping combustion with oxygen uncoupling (CLOU) is a related process in which fuel is combusted in oxygen released as a gas phase from the oxygen carrier rather than by directly reducing the carrier. CuO (copper (II) or cupric oxide) is a common carrier which releases oxygen at c. 900 C to form Cu2O (copper (I) or cuprous oxide). Oxygen uncoupling is beneficial in the case of solid fuel combustion (e.g., pulverized coal), since fuel components such as char and volatile compounds are more efficiently oxidized in gaseous oxygen than by direct reaction with the metal oxide carrier. Current development of chemical looping systems, using interconnected fluidized bed reactors, is further discussed in Section 7.2.6.

7.2.3 Temperature swing adsorption/desorption The use of CaO as a regenerable sorbent for CO2 is an example of a temperature swing process that was first proposed in the 19th century. In the temperature range 600800 C the carbonation reaction proceeds rapidly and high sorbent capacity can be achieved, while the familiar calcining reaction, releasing CO2, is favored at temperatures above 900 C. A pilot-scale post-combustion separation plant has been demonstrated, using interconnected fluidized bed carbonation and calcining reactors, as described in Section 7.2.6. Natural calcium-based sorbents, commonly derived from limestone, have the disadvantage that sorbent capacity degrades with repeated regeneration, with a typical loss of 50% of capacity after 5 cycles and 80% after 2040 cycles. This is largely due to the loss of micropore volume (pore diameter ,200 nm) and surface area as a result of physical changes in the sorbent, such as the sintering of micrograins and the collapse of the high-surface-area micropore structure. Sorbents derived from calcined dolomite (CaCO2  MgCO3) or huntite (CaCO3  3MgCO3) exhibit improved durability under repeated calcining. This is attributed to the presence of MgO in the calcined product, which remains inert in the carbonation reaction at high-temperature.

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Electric swing adsorption One disadvantage of desorption by temperature swing is the relatively long time needed to heat the sorbent bed during the desorption step and then cool the bed for the next adsorption step. As noted earlier, extended cycle times lead to larger adsorption beds for a given throughput rate and to higher capital costs. Electric swing adsorption (ESA), or electrothermal desorption, is a variant of TSA in which the sorbent is heated by Joule heating—i.e., by passing a current through the resistive sorbent material. This allows very fast heating of the sorbent bed, overcoming the long desorption period typically inherent in TSA cycles. When integrated into a larger process, TSA can usually benefit from the cheap availability of low-grade waste heat to provide energy for heating the sorption bed, whereas ESA requires high-grade electrical energy. This will increase both the operating costs and the carbon penalty of the process, unless the electric power is delivered from a zero-emissions source.

7.2.4 PSA processes The PSA concept was developed by the Esso Research and Engineering Company and published in a 1960 patent that disclosed a dual-bed, two-step cycle known as the Skarstrom cycle. The process is illustrated in Figure 7.12 as applied to air separation. Feed air is pretreated by compression, drying, and filtering and then flows into one of two parallel adsorption beds (A). Here nitrogen is adsorbed and oxygen passes through the bed and is recovered as the first product stream. While the first bed is operating in this mode, the sorbent material in the second bed (B) is being regenerated by releasing the pressure, recovering nitrogen as the second product stream. After depressurization, nitrogen recovery is increased by purging bed B with a fraction of the bed A product stream, the cycle ending before the purge stream breaks through the bed.

Step 1a

Bed A in adsorption

O2

Bed B in depressurization

N2

Air

O2

Bed A in adsorption

Step 1b

Step 2a

Air

Air

Figure 7.12 Skarstrom PSA cycle.

O2 purge Bed B in depressurization

N2

Bed A in depressurization

N2

Bed B in adsorption

O2

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In the second part of the cycle, the functions of the two beds are reversed, with repressurization and adsorption taking place in bed B and regeneration (N2 release and purge) in bed A. The process can be represented by the scheme shown in Figure 7.13, in which the upper schematic shows (from left to right) the successive cycle steps for bed A, while the table shows how these are phased over the two beds. Arrows indicate increasing or decreasing pressure in the bed. This format will be useful in describing more complex PSA cycles in the following sections. The nomenclature of this schematic, including terms that will appear in the later discussion, is summarized in Table 7.4. Although the simple Skarstrom cycle has not been applied to commercial air separation, due to low product recovery and high energy requirements, it is widely used for air drying using synthetic zeolites or activated alumina to adsorb water vapor. A disadvantage of this simple cycle is that the light product reflux step (the O2 purge in the Figure 7.12) causes a dilution of the heavy (sorbate-rich) component relative to the initial feed, and as a result it is difficult to achieve high-purity for the heavy product. Several improvements have been made to the Skarstrom cycle, including initial pressurization using light product, CoD after the initial feed step, one or more pressure-equalization steps, and a heavy product reflux step, as described in Table 7.5. While the addition of reflux steps increases product purity and recovery, either the flow rate or duration of the reflux step must be controlled to avoid breakthrough of the reflux into the other product stream, reducing throughput of the overall system. To illustrate these improvements, Figure 7.14 shows the Skarstrom cycle with LPP and CoD. Note that “T” in the figure represents a tank holding light product for the LPP and LR steps. Further improvements to these adsorption cycles are being developed to optimize the process for CO2 capture from flue gases and are described in Section 7.2.1. PSA has been used since the 1980s for the purification of hydrogen produced by steam methane reforming (SMR) followed by the WGS reaction—a process commonly used in oil refining to generate hydrogen for hydrotreating heavier crude oils.

Light Product PH

PH

PH

PL

Bed A PL

PL

Feed

Heavy Product

Bed

Step

1a

1b

2a

2b

A

FP

F

CnD

LR

B

CnD

LR

FP

F

Figure 7.13 Schematic and cycle sequence chart of the two-bed Skarstrom PSA cycle.

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Table 7.4 PSA process schematic nomenclature Symbol

Description

CnD CoD E EQ1,2,3 F FP HP HR LP LPP LR P PH PI P1,2,3 PL

Counter-current depressurization Co-current depressurization Evacuation (VSA) Pressure-equalization step 1, 2, 3 Feed Feed pressurization Heavy product (sorbate-rich) Heavy product reflux Light product (sorbate-lean) Light product pressurization Light product reflux Purge High operating pressure Intermediate pressure Intermediate pressures 1, 2, 3 Low operating pressure

A CCS demonstration project using VPSA at the Valero refinery, Port Arthur, TX, has been in operation since 2012, with over 1 Mt-CO2 captured for use in enhanced oil recovery (Baade et al., 2012). The SMR and WGS product stream is typically delivered at a pressure of B2 MPa and temperature of 850950 C. CO2 removal from the hydrogen product stream using PSA can recover 90% of the hydrogen in the feed stream with a purity of more than 99.99%. Systems can simultaneously deliver H2 and CO2 at highpurity and typically operate with a 3- to 10-min cycle time. Continuous development has resulted in commercial systems that deliver high reliability at low capital and operating costs. This separation can also be achieved using a chemical looping approach as described in Section 7.2.6.

Vacuum swing adsorption If the feed gas to a separation process is at or near ambient pressure, the energy penalty associated with compression to achieve an elevated feed pressure typical of a PSA cycle can be minimized or avoided by operating the cycle with PL below

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Table 7.5 Skarstrom cycle improvement steps Cycle step

Description

Light product pressurization

Light product purity can be improved by using a stream of light product rather than raw feed to bring the sorption bed up to highpressure before the main feed step. This necessitates a shift from two-bed to four-bed configuration for continuous operation, since with LPP the feed is active in only one of the four steps Co-current Co-current depressurization reduces the mass of feed plus LP reflux in depressurization the pore space of the sorption bed and allows the heavy product to start desorption while the light product is being produced, resulting in a higher-purity heavy product Pressure-equalization Interconnection of two beds to achieve pressure-equalization improves energy efficiency by transferring momentum from a bed that is in the pressure-reducing stage after feed to another bed in the pressure-increasing stage leading up to the feed step Heavy reflux Addition of a heavy product reflux to the CoD step increases heavy product purity in the later counter-current depressurization and light product reflux steps, but requires recompression of the heavy product up to the full feed pressure

Light Product T

PH

PI

PI

PH

PL

PL

PL

Bed A PH

Feed

Heavy Product 1

2

3

4

5

A

F

CoD

CnD

LR

LPP

B

CoD

CnD

LR

LPP

F

C

CnD

LR

LPP

F

CoD

Bed

Step

etc...

Figure 7.14 Five-step Skarstrom PSA cycle with LPP and CoD.

ambient pressure. Vacuum swing adsorption (VSA) is such a variant of PSA in which a partial vacuum is applied to the downstream end of the sorbent bed during the feed stage, to draw in a low-pressure feed stream, and also during desorption to improve product purity. The product purity and separation efficiency of a PSA

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system may also be increased by applying a vacuum to the bed under regeneration, resulting in a hybrid vacuum and pressure swing adsorption (VPSA) cycle. A VSA cycle incorporating a depressurization step to an intermediate pressure followed by evacuation (E) at a pressure below ambient was patented in 1957 by French engineers P. Guerin de Montgareuil and D. Domine. This cycle can be implemented with a wide range of operating schemes and bed numbers, and a schematic of two-bed version is shown in Figure 7.15. The GuerinDomine cycle performs significantly better in air separation than the Skarstrom cycle and has been commercially applied for mid-sized air separation units (up to B340 t-O2/day) since the 1970s.

High-frequency pressure cycling In PSA, the amount of sorbent required to achieve a given sorbate-throughput rate is directly related to the frequency of the pressure cycle (Equation (7.8)), with a high-frequency resulting in a higher throughput rate. Raising the cycling frequency therefore has the potential to reduce the capital cost of PSA systems by reducing sorbate volume and the related physical system size. Since mechanical switching of valves can result in early mechanical failure, alternative methods of rapidly cycling the system pressure are under investigation. Possible approaches include the use of reciprocating (piston) or pressure wavebased systems.

7.3

Adsorption technology RD&D status

7.3.1 Advanced PSA/VSA cycles Optimization of the PSA cycle configuration is an active area of research, with the aim of achieving high-purity product streams and to minimize energy consumption (see Webley et al., 2017). Early improvements described above included the Light product (O2)

PH

PI

PI

PI

PI

PH

PL

PL

Bed A

Feed

Bed

Step

Heavy product (N2) 1

2

3

4

A

FP

CoD

E

LPP

B

E

LPP

FP

CoD

Figure 7.15 Two-bed air separation unit using the GuerinDomine cycle.

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introduction of refluxes of either light (LR) or heavy product (HR) to improve the purity of one or other product streams. The combination of LR and HR into a single dual-reflux cycle has been shown in process simulations to outperform other cycle configurations in maximizing recovery of a high-purity CO2 heavy product stream from high-temperature flue gases. The dual-reflux cycle is shown schematically in Figure 7.16. The heavy reflux can be delivered either from the countercurrent depressurization step, as shown here, or from the subsequent light reflux step, the former having the advantage of requiring the reflux product to be compressed only from an intermediate pressure to PH rather than from PL to PH. With the use of dual refluxes, the PSA cycle begins to mimic the operation of a distillation column. Optimization of the dual-reflux cycle is continuing, building on this analogy to develop even more flexible cycles.

Adsorption heat storage As noted in Section 7.1, temperature management is an important aspect of sorption process optimization, since heating during adsorption and cooling before or during desorption reduce working capacity, and various heat exchange systems have been employed to mitigate temperature change in adsorption beds. One option that has received recent attention is the incorporation of PCMs within the sorption bed, either

Light product T

PH

PH

PH

PL

PL

Bed A PL T

Feed

Heavy product

1

2

3

4

5

A

F

HR

CnD

LR

LPP

B

HR

CnD

LR

LPP

F

C

CnD

LR

LPP

F

HR

D

LR

LPP

F

HR

CnD

E

LPP

F

HR

CnD

LR

Step

Bed

PH

Figure 7.16 Five-bed dual-reflux PSA cycle with heavy reflux from counter-current depressurization.

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as part of the bed structure, as separate elements interspersed among the sorbent particles or in the form of hybrid sorbentPCM particles (see Horstmeier et al., 2016). A PCM, such as paraffin wax encapsulated in a copper shell, with a phasechange temperature just above the bed temperature at the start of adsorption, will store the released heat of adsorption as latent heat of fusion and make this heat available to maintain bed temperature on desorption. By limiting the temperature fluctuations in the sorbent bed, increased working capacity and improved product purity can be achieved.

7.3.2 Sorption-enhanced reactions High-temperature adsorption has potential applications in pre-combustion CO2 capture and is the subject of a number of R&D projects. The production of hydrogen through SMR and the WGS reaction (Reactions (7.13) and (7.14)) is an important example. SMR

CH4 1 H2 O2CO 1 3H2

(7.13)

WGS

CO 1 H2 O2CO2 1 H2

(7.14)

CO2 removal Overall reaction

CO2 1 CaO2CaCO3 CH4 1 2H2 O 1 CaO ! CaCO3 1 2H2

(7.15) (7.16)

Reversible chemical reactions, such as the WGS reaction, can reach an equilibrium state before the full consumption of the reactants as a result of the buildup of reaction products and the increasing rate of the reverse reaction. Removal of one of the reaction products from the gas phase in the reaction zone, e.g., by adsorption, enables the reaction to reach completion. PSA has been commercially applied to purification of the hydrogen product stream from these reactions for many years. One aim of current research is to move the adsorption application further upstream, into the high temperatures and pressures of the SMR and WGS reactors. The conditions in SMR and WGS reactors put severe requirements on sorbents, including: G

G

G

High CO2 loading capacity and sufficiently fast adsorption and desorption kinetics Mechanical and chemical stability for long periods, at temperatures up to 900 C and pressures up to 4.0 MPa Tolerance to high stream partial pressures, with psteam/pCO2 typically greater than 20 in steam reforming

Sorption-enhanced WGS In conventional SMR, typically 7080% of the methane feed is converted to hydrogen in a reactor at a temperature of 700950 C and a pressure of 1.54.0 MPa,

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yielding a product stream with the composition shown in Table 7.6. A sorptionenhanced WGS (SEWGS) reactor, using a WGS catalyst and high-temperature CO2 sorbent, can remove 90% of the carbon from the fuel gas product stream. If higherpurity hydrogen is required, e.g., for zero-emission combustion, an additional PSA stage can be added downstream of the sorption-enhanced reactor (SER). A six-bed laboratory-scale proof-of-concept SEWGS reactor was developed as part of the European Unionfunded CACHET and CAESAR projects. The prototype uses a pressure swing cycle with three pressure-equalization steps, as shown schematically in Figure 7.17. The pressure-equalization steps improve the efficiency of the cycle by transferring energy between depressurizing and repressurizing beds, while the sequencing

Table 7.6 SEWGS feed and product stream compositions Component

Steam-reformed feed gas

SEWGS product gas

H2 H2O CO CO2 CH4

57% 16% 16% 10% 0.5%

89% 8% 0.5% 2% 0.5%

Steam

Light product (H2)

PH

PH

P2

P1

P1

PH

P2

PL

PL

PL

P1

P2

P3

P1

P2

P3

PH

Bed A

Heavy product (CO2)

Feed

Bed

Step

1

2

3

4

F

HR

2

EQ1 LPP

3

EQ3 EQ2 EQ1 LPP P

5

EQ3 CnD

6

HR

6

7

EQ2 EQ3 CnD

1

4

5

F

EQ2 EQ3 CnD

Figure 7.17 SEWGS cycle schematic.

P

9

F

HR

11

12

EQ3 EQ2

P

EQ2 EQ3 CnD F

EQ3 EQ2 EQ1 LPP P

10

EQ3 EQ2 EQ1 LPP

EQ2 EQ3 CnD

HR

EQ3 EQ2 EQ1 LPP P

8

HR

P

EQ2 EQ3 CnD F

EQ3 EQ2 EQ1 LPP

HR

EQ2 F

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of the steps maximizes the purity of the two product streams. However, the low delivery pressure of the CO2 plus steam product stream (B0.2 MPa) and the requirement for high-pressure CO2 (B3.0 MPa) for the heavy reflux, step are challenges for the energy efficiency of the overall process. The reactor in these trials uses a potassium carbonate (K2CO3)-promoted HTC sorbent and an ironchromium catalyst, both deposited on a structured support. Aspects of the SEWGS process investigated in these EU projects included: G

G

G

G

G

Verifying the stability of the sorbent and catalyst Optimizing flow rates of the feed, heavy reflux, and purge steps Minimizing CO2 slip into the fuel gas product stream Maximizing CO2 purity and delivery pressure Minimizing catalyst requirement to reduce reactor vessel sizes and costs

The CAESAR project concluded that, at c. h25/t-CO2 avoided, IGCC with SEWGS was a more economically viable capture process than IGCC with capture by Selexol or post-combustion capture using amines in a coal-fired plant. An industrial pilot plant based on these results is under construction as part of the STEPWISE project, part of the EU’s Horizon 2020 research and innovation program. The pilot plant, commissioned in the mid-2017, produces hydrogen and captures 14 t-CO2/day from blast furnace gas at the Swerea Mefos steel plant located in Lulea˚, Sweden. Rather than the multi-bed reactor assessed at lab scale in the earlier projects, the pilot uses a single column containing some 2.5 t-sorbent and will focus on the steam requirement to achieve the target separation efficiency, as well as cycle design and heat management.

Sorption-enhanced steam reforming As an alternative to enhancing the WGS reaction, the overall SMR plus WGS reaction can also be achieved in a single sorbent-enhanced reaction step (Reaction (7.16)). The removal of CO2 using CaO shifts the overall reaction to the right, and the presence of a catalyst allows the reaction to proceed without the need for a separate WGS stage, enabling almost complete conversion at significantly lower temperatures (400600 C). The lower operating temperature can result in significant cost benefits compared to conventional reforming, since expensive alloy steels are not required and the overall size of heat exchange equipment can be reduced. Figure 7.18 shows a process schematic for an SER-based hydrogen production system, using a simple dual-bed reactor. A methane plus steam mixture is fed into reactor bed 1, containing a high-temperature CO2 sorbent and a SMR catalyst. The sorption-enhanced reaction results in a hydrogen plus steam product stream, while CO2 is adsorbed within the reactor. The reaction step continues until the H2 effluent purity drops to a preset value. Concurrently, reactor 2 is fed with steam as a purge gas to remove CO2, with desorption enhanced either by a pressure or temperature swing, or both. Water is condensed from the desorbed stream, yielding a CO2 product stream suitable for compression and storage.

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(1) SER bed in adsorption

H2+ Steam Combustor

Natural gas Steam

Air

(2) SER bed in regeneration

Compressor

Gas turbine

Generator

Turbine exhaust Steam

CO2 to compression Condenser Water

Figure 7.18 Hydrogen production using sorption-enhanced steam reforming.

Laboratory-scale proof-of-concept experiments have confirmed the high H2 and very low CO and CO2 concentrations in the light product stream compared to conventional SMR. Further development is ongoing, focusing on: G

G

G

G

Identifying sorbentcatalyst combinations with improved properties, including dual function materials combining steam reforming and in situ CO2 removal Optimization of reaction conditions (temperature, pressure, water vapor presence) and reactor configuration (fixed and circulating systems) Natural sorbent selection criteria and pre-treatment for low attrition For circulating systems (CFB), optimizing operating conditions to reduce sorbent attrition

7.3.3 Adsorption-based direct air capture Compared to the pilot-scale chemical absorption experiments using NaOH, as described in Section 6.3.6, adsorption is relatively less developed as a technique for DAC, despite the potential advantage of lower regeneration energy requirements when compared to absorption. Bench-scale experimental studies have been reported for a number of potential sorbents, the most commonly studied being amines impregnated or tethered (i.e., bonded) to a variety of supporting materials including silica, porous polymer networks, and MOFs. Sorption capacities of around 1 mol-CO2/kg have been demonstrated in laboratory experiments although there is a trade-off between increasing capacity and cycle time, since high amine loading reduces contactor permeability. This slows the adsorption rate which, at DAC conditions, is controlled by CO2 diffusion within the sorbent material. Supported amine sorbents can be regenerated using low-grade steam (70105 C) which can be cheaply generated using solarthermal heating or supplied via integration into other industrial processes. K2CO3-impregnated porous alumina (γ-Al2O3) has also been studied for DAC application. Chemisorption of CO2 results in the production of crystalline potassium bicarbonate KHCO3 (see Reaction (6.10)) and potassium dawsonite (KAlCO3(OH)2)

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on the alumina surface. A sorption capacity similar to supported amines has been demonstrated in laboratory experiments, although regeneration requires heating to 250300 C in order to decompose the dawsonite fraction. While most investigators envisage practical implementation of adsorption-based DAC using a monolithic contactor of the type found in automotive catalytic converters, a CFB system has also been proposed, based on experimental performance of a silica-supported amine in a bubbling fluidized bed adsorber. Total energy requirement of around 68 GJ/t-CO2 are reported for various adsorption-based DAC systems, roughly half that required for the NaOH absorption process discussed in Section 6.3.6. Focus areas of ongoing RD&D include optimizing amine support structures to achieve high loading with rapid adsorption kinetics, as well as demonstrating longterm sustained sorbent performance and operability of a practical contactor or CFB system.

7.3.4 Novel sorbent materials The search for novel sorbent materials which address the shortcomings of current systems is an active research area, and some of the promising lines of investigation are summarized here.

High-temperature sorbents Natural calcium-based minerals, such as limestone and dolomite, have a number of advantages as high-temperature CO2 sorbents, including fast carbonation and calcination reaction kinetics, natural abundance, and low cost. However, as noted above they suffer from a gradual loss of sorption capacity with repeated cycling, and degradation in the presence of sulfur due to the formation of non-regenerable calcium sulfate. In applications where a catalyst is added, such as in SMR, any mismatch between catalyst and sorbent lifetimes is problematic, requiring either the premature disposal of still-active catalyst or the separation of mixed solid catalyst and sorbent. Considerable research effort has been aimed at developing more reliable hightemperature sorbents, based on lithium and sodium, as well as calcium. Among the candidate sorbents that have been tested are: G

G

G

G

Lithium zirconate (Li2ZrO3) Lithium orthosilicate (Li4SiO4) Sodium zirconate (Na2ZrO3) Calcium aluminate (CaAl2O4)

These sorbents can be carbonated in SMR reactions, e.g.: Li4 SiO4 1 CH4 1 2H2 O ! Li2 SiO3 1 Li2 CO3 1 4H2

(7.17)

and regenerated through the analogous calcining reaction: Li2 SiO3 1 Li2 CO3 1 heat ! Li4 SiO4 1 CO2

(7.18)

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The zirconate sorbents are found to give high hydrogen yield in SMR experiments but suffer from slow reaction kinetics (lithium zirconate) and catalyst poisoning (sodium zirconate). Further investigation of carbon-based sorbents also continues, investigating synthetic CaO sorbents and treatment methods to address the performance issues of natural calcium-based sorbents. One such area is the chemical modification of high-surface-area carbon-based sorbents by the introduction of CaO and CaO  MgO, resulting in significantly enhanced high-temperature sorption capacity for CO2.

Composite sorbents Composite sorbents, in which the active sorbent material is incorporated into a supportive or protective structure, can overcome some of the limitations of the bare sorbent, such as reducing degradation to extend sorbent lifetime, as well as exhibiting other beneficial characteristics. Examples of such composite sorbents include the incorporation of functionalized amine sorbents into mesocellular siliceous foams or of solid sorbent powder into a substrate comprising a network of hydrophobic polymer filaments (Berger et al., 2017). The later example, under development by the EPRI and W. L. Gore, enables TSA regeneration by direct steam injection which would normally not be possible due to the adverse effect of moisture on sorbent performance (capacity, degradation, etc.). This has numerous advantages including improved energy efficiency and reduced cycle time leading to increased system throughput.

7.3.5 Metalorganic frameworks The identification and assessment of new MOF sorbents to achieve high CO2 selectivity and capacity has been a very active and fruitful area of research in recent years, particularly since 2009. Novel adsorption phenomena observed in MOFs, such as gate opening and breathing, and non-Langmuir adsorption behavior, have the potential to achieve a step-change reduction in energy penalty for sorbent regeneration. These significant developments are discussed below. Other areas of current MOF research include: G

G

G

G

G

G

Reducing the impact of impurities, including water, on sorbent capacity MOF modification (e.g., functionalization, impregnation, doping, decoration) with a variety of materials, either post-synthetic or during synthesis as MOF structural elements Design of TSA and PVSA operating cycles to optimize sorbent performance MOF sorbents to improve PVSA energy efficiency by removing the vacuum requirement Impact of synthesis methods on MOF morphology and properties Scale-up of MOF synthesis methods, for low cost large-scale production

Gate opening and breathing phenomena in flexible MOFs Reversible structural transitions in flexible MOFs as a result of external stimuli, including light, heat, and the adsorption of guest molecules, were first reported

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between 2001 and 2005 and have been extensively investigated since then. Two of the most widely studied such transitions are “gate opening” which refers to the transition from a closed, non-porous phase to an open, porous one, and “breathing” which refers to an expansion and contraction of the MOF unit cell. These transitions, illustrated schematically in Figure 7.19, occur as a result of the movement (e.g., rotation, bending) of the MOF organic linkers and in many cases occur exclusively in response to the presence of CO2. This is because the energy of adsorption of the guest molecule in the MOF is sufficient to activate the transition for CO2 but not for other gases. As also shown in the figure, the adsorption isotherms differ significantly from the classical Langmuir type discussed above.

Phase-change functionalized MOF sorbents A new class of “phase-change” functionalized MOF sorbents has recently been reported by McDonald et al. (2015) which also exhibit non-Langmuir adsorption behavior. The step-shaped adsorption isotherms of these sorbents (Figure 7.20) show that, at a given temperature, sorbate loading increases from near zero to full capacity over a very narrow pressure range (compare to Figure 7.2) and that the full working capacity can be achieved with a narrower temperature swing than for sorbents exhibiting a Langmuir isotherm. This behavior was demonstrated in diamine-appended MOFs and arises because the adsorption of a CO2 molecule by the amine at one metal site (forming ammonium carbamate) destabilizes the amines at adjacent metal sites resulting in a chain

Sorbent loading (mol/kg) Desorption

Gate closing

Adsorption

Gate opening & breathing

Sorbate molecule

Pressure

Figure 7.19 Schematic of gate opening and unit cell breathing in flexible MOFs. Source: After Hyun et al. (2016).

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Carbon Capture and Storage

Sorbent loading (mol/kg)

PAdsorption

PDesorption

TSA working capacity

∆TSA

TL

TM

TH

Pressure

Figure 7.20 Step-shaped adsorption isotherms of a “phase-change” sorbent.

reaction that drives the adsorption of CO2 and the reorganization of the amines into an ordered chain of ammonium carbamates. Unlike classical sorbents, where a low adsorption temperature is needed to maximize working capacity, the efficiency of phase-change sorbents increases at higher temperatures, widening the potential operating temperature range for adsorption processes.

7.3.6 Chemical looping RD&D status Chemical looping combustion A large number of CLC pilots have been executed by research teams around the world, the two largest being a 3 MWth plant using CaO as carrier at Alstom Windsor Labs, CT, and a 1 MWth plant using ilmenite at the University of Darmstadt, Germany (the E´clair-Acclaim project, also supported by Alstom). A 3year development project, supported by the US DOE NETL’s Advanced Combustion Systems Program, commenced in 2013 with the aim of closing identified technology gaps in the Alstom CaO carrier pilot. This would improve readiness for an industrial-scale demonstration project (1050 MWth) from 2017 to 2020, with commercial deployment (c. 150 MWth scale) from 2020. CLOU has been proof-of-concept tested at laboratory-scale (1.5 kWth), using a bituminous coal fuel and CuO as the oxygen carrier, and demonstrated a carbon capture efficiency of 9599%. Alongside these demonstration efforts, continuing areas of CLC research include the screening of alternative oxygen carrier materials (e.g., mixed oxides) for high reactivity toward specific fuels, and the optimization of oxygen carrier particles, including support materials and production processes, for long-term mechanical stability and reactivity.

Adsorption capture systems

181

CaO looping post-combustion capture CaO looping is being investigated for post-combustion CO2 capture, using interconnected fluidized bed adsorption and regeneration reactors. Figure 7.21 illustrates the physical configuration, in which hot flue gases enter the base of the carbonation reactor (A), along with a feed of hot CaO. The fine sorbent particles rise in the column along with the flue gas stream and are separated in a cyclone separator (C1). Depleted flue gases are released while the carbonated sorbent (CaCO3) is conveyed to the base of the regenerating bed (B). Calcination at 900 C results in the release of CO2, which is separated from regenerated sorbent (CaO) by a second cyclone separator (C2). The loop is completed by conveying the regenerated sorbent to the base of the carbonation reactor. An equivalent CaO looping concept can also be used to remove CO2 from the H2 1 CO2 syngas product stream from the WGS reaction, commonly achieved using fixed-bed systems. Ongoing research into synthetic calcium-based sorbents for chemical looping aims to sustain sorbent capacity through repeated regeneration cycles. Mixed sorbents such as CaO(75%)/Ca12Al14O33(25%) or CaO(90%)/Al2O3(10%) have been shown to sustain higher carrying capacity over repeated cycles than pure CaO, attributed to the higher sintering temperature. Alternatives to CaO, such as lithium silicate (Li4SiO4), have also been investigated for high-temperature chemical looping reactors, with the aim of identifying sorbents with lower regeneration temperatures. Lithium silicate can be regenerated at a temperature of B800 C, significantly lower than the temperature required for calcining CaCO3. Several pilot-scale CaO looping capture systems have been reported, including a 1.9 MWth plant capturing 1 t-CO2/h from flue gas at the Taiwan Cement Company’s Ho-Ping cement plant in Hualien, Taiwan, and a 1.7 MWth plant capturing up to 95% of CO2 from a flue gas slip stream at the Hunosa operated 50 MWe CFBC power plant at La Pereda in Spain, the latter being part of the EU-funded

flue gas

Heat recovery

Heat recovery 650°C

900°C C1

Carbonator

A

CO2 compression

C2

CaO

B

Calciner

CO2 reduced

Coal, CaCO3 CaCO3 Heat recovery Flue gas

Gas pre heat

CaO, CaCO3 O2 Ash

Figure 7.21 Flue gas capture using CaO looping.

Gas pre heat

O2

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Carbon Capture and Storage

“CaOling” project. Further process evaluation has also been undertaken using a 1 MWth pilot plant constructed at Technische Universita¨t Darmstadt a part of the EU’s SCARLET project, with the aim of providing a basis for scale-up to a 20 MWth demonstration plant (Helbig et al., 2017).

Hybrid combustiongasification by chemical looping The versatility of chemical looping is well illustrated by the proposed combination of two calcium-based chemical loops into a hybrid combustiongasification process. The first loop uses CaSO4 as an oxygen carrier to gasify coal in a partial oxidization step, completing the loop by oxidation of CaS in air: 4C 1 CaSO4 ! 4CO 1 4CaS

(7.19)

CaS 1 2O2 ! CaSO4

(7.20)

In the presence of steam, the partial oxidation product is water-gas shifted to produce H2 and CO2, and a second CaO loop is then used to remove CO2 from the syngas stream. A schematic of this hybrid system, which is currently at the pilot-testing stage, is shown in Figure 7.22. Three interconnected fluidized bed reactors are shown: a reducer, calciner, and oxidizer. The reducer is fed with pulverized coal or other carbonaceous fuel, steam, and the chemical sorbents CaSO4 and CaO. The fuel gasification, WGS, and CaO carbonation reactions take place in this reactor, producing a product gas stream of pure hydrogen. The solid reaction products are carried out of the top of the reactor with the gas product stream and separated in the first of three cyclone separators. The solids are then conveyed to the second reactor, where the CaCO3 is calcined and CO2 released. Heat for the calcination reaction is provided by a heat exchange loop from the combustion reactor, using bauxite as the heat CO2

Calciner

H2

N2

Reducer

Oxidizer CaCO3

CaS, CaCO3, Inerts Coal

Steam

Air CaSO4, CaO, Inerts

CaS, CaO, Inerts

CaSO4, CaO, Inerts

Figure 7.22 Hybrid combustiongasification chemical looping process.

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183

transfer medium (not shown in the figure). Solid products are then conveyed to the final reactor, where CaS is oxidized in a heated air stream. Attrition products from the CaSO4 and CaO particles, as well as other inert combustion products, are removed from circulation, while makeup carbonate is added to the calciner as required. Reflux of the solid reaction products from the reducing and oxidation reactors can be used for additional process control. Development of a 3 MWth prototype chemical loopinggasification facility is being progressed by GE Power, in parallel with the CLC development work described above. It is currently envisaged that the industrial-scale demonstration project planned from 2017 to 2020 may be either a combustion plant for power generation or a gasification plant for integration into a refinery.

7.4 References and resources 7.4.1 References Baade, W., Farnand, S., Hutchinson, R., Welch, K., 2012. CO2 capture from SMRs: a demonstration project. Hydrocarbon Process. 91 (9), 6368. Berger, A.H., Horowitz, J.A., Machalek, T., Wang, A., Bhown, A.S., 2017. A novel rapid temperature swing adsorption post-combustion CO2 capture process using a sorbent polymer composite. Energy Procedia. 114, 21932202. Chaffee, A.L., et al., 2007. CO2 capture by adsorption: materials and process development. Int. J. Greenhouse Gas Control. 1, 1118. Chui, J., Andrus, H., 2014. Alstom’s chemical looping technology program update. Presented at the 2014 USDOE/NETL CO2 Capture Technology Meeting. 29 July1 August 2014, Pittsburgh, PA. Didas, S.A., Choi, S., Chaikittisilp, W., Jones, C.W., 2015. Amine2oxide hybrid materials for CO2 capture from ambient air. Acc. Chem. Res. 48, 26802687. Grande, C.A., Rodrigues, A.E., 2007. Electric swing adsorption for CO2 removal from flue gases. Int. J. Greenhouse Gas Control. 2, 194202. Gupta, T., Ghosh, R., 2015. Rotating bed adsorber system for carbon dioxide capture from flue gas. Int. J. Greenhouse Gas Control. 32, 172188. Hanak, D.P., Anthony, E.J., Manovic, V., 2015. A review of developments in pilot-plant testing and modelling of calcium looping process for CO2 capture from power generation systems. Energy Environ. Sci. 8, 21992249. Helbig, M., Hilz, J., Haaf, M., Daikeler, A., Stro¨hle, J., Epple, B., 2017. Long-term carbonate looping testing in a 1 MWth pilot plant with hard coal and lignite. Energy Procedia. 114, 179190. Horstmeier, J.F., Gomez Lopez, A., Agar, D.W., 2016. Performance improvement of vacuum swing adsorption processes for CO2 removal with integrated phase change material. Int. J. Greenhouse Gas Control. 47, 364375. Hufton, J.R., et al., 2005. Development of a process for CO2 capture from gas turbines using a sorption enhanced water gas shift reactor system. Proceedings of the 7th International Conference on Greenhouse Gas Control Technologies. Elsevier, Oxford, UK. Hyun, S.M., et al., 2016. Exploration of gate-opening and breathing phenomena in a tailored flexible metal2organic framework. Inorg. Chem. 55, 19201925.

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Ishibashi, M., et al., 1996. Technology for removing carbon dioxide from power plant flue gas by the physical adsorption method. Energy Convers. Manage. 37, 929993. Jansen, D., et al., 2013. SEWGS technology is now ready for scale-up!. Energy Procedia. 37, 22652273. Lee, S.-Y., Park, S.-J., 2015. A review on solid adsorbents for carbon dioxide capture. J. Ind. Eng. Chem. 23, 111. Lyngfelt, A., Linderholm, C., 2014. Chemical-looping combustion of solid fuels—technology overview and recent operational results in 100 kW Unit. Energy Procedia. 63, 98112. McDonald, T.M., et al., 2015. Cooperative insertion of CO2 in diamine appended metalorganic frameworks. Nature. 519, 303308. Okumura, T., Yoshizawa, K., Nishibe, S., Iwasaki, H., Kazari, M., Hori, T., 2017. Parametric testing of a pilot-scale design for a moving-bed CO2 capture system using lowtemperature steam. Energy Procedia. 114, 23222329. Reynolds, S.P., Ebner, A.D., Ritter, J.A., 2005. New pressure swing adsorption cycles for carbon dioxide separation. Adsorption. 11, 531536. Stylianou, K.C., Queen, W.L., 2015. Recent advances in carbon capture with metalorganic frameworks. Chimia. 69, 274283. Veselovskaya, J.V., Derevschikov, V.S., Kardash, T.Y., Stonkus, O.A., Trubitsina, T.A., Okunev, A.G., 2013. Direct CO2 capture from ambient air using K2CO3/Al2O3 composite sorbent. Int. J. Greenhouse Gas Control. 17, 332340. Wilcox, J., Haghpanah, R., Rupp, E.C., He, J., Lee, K., 2014. Advancing adsorption and membrane-separation processes for the gigaton carbon capture challenge. Annu. Rev. Chem. Biomol. Eng. 5, 479505. Webley, P.A., Qader, A., Ntiamoah, A., Ling, J., Xiao, P., Zhai, Y., 2017. A new multi-bed vacuum swing adsorption cycle for CO2 capture from flue gas streams. Energy Procedia. 114, 24672480. Zhang, W., Liu, H., Sun, C., Drage, T.C., Snape, C.E., 2014. Capturing CO2 from ambient air using a polyethyleneiminesilica adsorbent in fluidized beds. Chem. Eng. Sci. 116, 306316.

7.4.2 Resources Adsorption.org (adsorption knowledge sharing site): www.adsorption.org Alstom (now GE) Power (chemical looping combustion/gasification development): www. ge-alstom.com CACHET/CESAR (early development of SEWGS technology): ECN (Energy Research Centre of the Netherlands; novel sorbents and sorption-enhanced reactions (SEWGS)): www.ecn.nl Fennell, P., Anthony, B. (Eds.), 2015. Calcium and Chemical Looping Technology for Power Generation and Carbon Dioxide (CO2) Capture. Elsevier, Amsterdam. Global Thermostat (Adsorption technology for direct air capture): www.globalthermostat. com Ha¨ring, H.-W. (Ed.), 2007. Industrial Gases Processing. Wiley-VCH Verlag GmbH, Weinheim, Germany. IFE (Institute for Energy Technology; high-temperature sorbents for sorption-enhanced reactions): www.ife.no/en/ife/main_subjects_new/energy_environment/klima International Conference on Chemical Looping: http://chemical-looping2016.com

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Ruthven, D.M., Farooq, S., Knaebel, K.S., 1994. Pressure Swing Adsorption. John Wiley & Sons, Inc., New York. STEPWISE project (SEWGS industrial pilot using blast furnace gas): www.stepwise.eu/ home/ Yang, R.T., 1987. Gas Separation by Adsorption Processes. Butterworth Publishers, London, UK.

Membrane separation systems

8

The first application of membranes for gas separation was in the 1980s, when techniques were developed for hydrogen separation, for example, from hydrotreaters in refineries, for oxygen/nitrogen separation, and for the separation of CO2 from natural gas, the latter either to process natural gas to sales quality or for EOR applications. A number of early membrane gas separation applications are summarized in Table 8.1. The technological breakthrough that brought membranes into large-scale industrial use was the development of composite polymer membranes, in which a thin selective layer is bonded to a thicker, non-selective, and inexpensive layer that provides mechanical support. Membranes have a number of potential applications in carbon capture, from hydrogen separation in pre-combustion capture systems to CO2 separation from post-combustion flue gases. A wide variety of different membrane techniques are potentially applicable, using proven technologies that are already deployed on an industrial scale as well as novel technologies, based on advanced materials, that are under research and development.

8.1

Physical and chemical fundamentals

Conceptually, a membrane acts as a filter, separating one specific component (the permeate) from a mixture of gases in a feed stream. This “filtration” process can involve a number of different physical and chemical processes, depending on the membrane design and materials, and these processes are discussed in this section. The two common membrane separation flow schemes are illustrated schematically in Figure 8.1. A feed gas stream enters the module and the permeate exits on the downstream side, having passed through the membrane. The feed stream minus permeate is termed the retentate and may either exit the module having been depleted of the permeate (as in the cross flow example A) or be continuously replenished (as in the dead-end flow case B). The key characteristic of membranes that determine the mechanism for transporting permeate molecules is porosity, and membranes are classified as either porous or non-porous. For porous membranes, the pore size determines the size of particles (molecules at the smallest scale) that can pass through the membrane, as shown in Table 8.2. At the macropore scale, gas flow is dominated by viscous forces, giving way to diffusion as the pore size reduces below the mean free path of gas molecules. ˚ , as the pore size approaches molecular dimensions, flow is increasingly Below 10 A Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00008-8 © 2017 Elsevier Inc. All rights reserved.

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Table 8.1 Early membrane separation applications and technologies Application

Company

Technology

Hydrogen recovery from ammonia production Nitrogen separation from air CO2 separation from methane and ethane CO2 separation from methane and ethane

Monsanto

Prisms hollow-fiber polymeric membranes Generons hollow-fiber polymeric membranes Acetyl activated non-porous cellulose acetate membrane Separext spiral-wound and hollowfiber cellulose acetate membranes

Dow Cynara/NATCO UOP-Honeywell

(B) Dead-end flow Feed

(A) Cross flow Feed

Retentate build up on membrane

Retentate

Counter current flow

Co-current flow

Permeate

Permeate

Figure 8.1 Membrane configurations: (A) cross flow and (B) dead-end flow.

Table 8.2 Porous membrane classification Pore classification

Pore size range

Filtration classification

Macroporous Mesoporous Microporous Nanoporous

˚) .50 nm (500 A ˚) 2
50 nm (20
500 A ˚) 1
2 nm (10
20 A ˚) ,1 nm (10 A

Microfiltration Ultrafiltration Nanofiltration Molecular sieving

dominated by surface interaction on the pore walls and is termed “molecular ˚ scale, a solution
diffusion transport sieving.” Once the pore size drops to the 1 A mechanism occurs rather than molecular sieving. These transport mechanisms are described in the following sections.

8.1.1 Porous membrane transport processes The physical nature of the gas transport process occurring in porous membranes depends on the size of pores in the membrane and on the temperature and pressure of the feed gas. The different transport regimes are characterized by the Knudsen

Membrane separation systems

189

number NKn, which is equal to the ratio of the mean free path of gas molecules for component i (λi) to the average pore diameter in the membrane (d0): NKn i 5 λi =d0

(8.1)

Viscous capillary flow If the membrane pore diameter is very large compared to the mean free path of the gas molecules (NKn , 0.001), the gas flux is governed by Poiseuille’s equation for viscous flow through capillaries: Ji 5 r 2 ΔPPav =ð8 μRTLÞ

(8.2)

where Ji is the flux of gas component i, ΔP is the differential pressure across the membrane, Pav is the average pressure within a capillary, r is the representative pore radius, μ is the gas viscosity, R is the gas constant, T is the temperature (K), and L is the length of the capillary (which, ignoring pore tortuosity, equals the membrane thickness). The flux can also be expressed in terms of the porosity (ε) of the membrane as: Ji 5 r 2 ΔP ε=ð8 μLÞ

(8.3)

A mixture of two gases in capillary flow will be characterized by a single average pressure and a single viscosity that will depend on the ratio of gases in the mixture. The ratio of fluxes of the two components (Ji/Jk) will depend on their partial pressure in the mixture and the transport will exhibit no selectivity between the components, since selectivity requires a transport mechanism that depends on characteristics of the individual components in the mixture.

Knudsen diffusion If the mean free path is very much larger than the membrane pore radius (NKn . 100), gas molecules will collide more frequently with the pore walls than they will with other gas molecules. This situation is termed free-molecule flow, or Knudsen flow (Figure 8.2), and the flux rate is determined by the Knudsen equation: Ji 5 Di ΔP=RTL 5 2r ΔP 8RT=πMi


1=2

=3RTL

(8.4)


1=2 is the Knudsen diffusion coefficient for component i where Di 5 2=3r 8RT=πMi and Mi is the molecular weight of the gas component. Equation (8.4) shows that if two gas species are being transported through a membrane under Knudsen flow, the flux ratio (Ji/Jk) varies inversely with the ratio of the molecular weights:
1=2 ðJi =Jk Þ 5 Mk =Mi (8.5)

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Feed

ΔP

Permeate

Viscous capillary (Poiseuille) flow

Knudsen diffusion

Figure 8.2 Viscous capillary flow and Knudsen diffusion.

Table 8.3 Porous membrane selectivity under Knudsen flow Gas components

Molecular weight ratio

Knudsen flux ratio

CO2/H2 CO2/CH4 CO2/N2 O2/N2

21.83 2.75 1.57 1.14

1/4.67 1/1.66 1/1.25 1/1.07

In the transition region between Knudsen flow and Poiseuille flow (0.001 , NKn , 100), correction factors are required to account for the varying effect of molecular and boundary collisions. Equations (8.4) and (8.5) apply to pure gases moving in straight cylindrical pores, and a correction factor is also needed to account for pore size distributions and for tortuous flow paths through actual membrane pore networks. Equation (8.4) can be corrected with a porosity
tortuosity factor ε/τ by replacing Di for a single pore by Di for a porous medium: Di Porous medium 5 Di Single pore  ε=τ

(8.6)

The molecular weight dependence in Knudsen flow introduces the possibility of selective flow of gases through the membrane. However, as shown in Table 8.3, the selectivity that can be achieved for common CCS gas separation problems is limited due to the relatively small molecular weight differences. Meso- and macroporous membranes exhibiting Knudsen flow are therefore not attractive for direct gas separation applications. However, these membranes are proposed for use in gas
liquid membrane contactors that are being developed as an alternative to amine absorption towers for CO2 recovery from flue gas. In this application flue gas flows through the bores of a hollow-fiber bundle membrane module (Section 8.2.1), with a CO2 absorbent

Membrane separation systems

191

CO2 lean flue gas

CO2 rich flue gas

Non-selective membrane

CO2 lean solvent

CO2 rich solvent

Figure 8.3 Gas
liquid membrane contactor for CO2 removal from flue gas.

liquid, such as an amine or amino acid salt solution, flowing in countercurrent through the shell side of the module. Figure 8.3 illustrates this membrane gas absorption process. In this application the membrane itself offers no selectivity, having a nominal pore diameter typically in the 10
200 nm range. However it serves to provide an interface between the gas and the solvent that offers very high surface-to-volume ratio for mass exchange between the gas and solvent. This application is discussed further in Section 8.7.2. An important assumption underlying the calculation of flux in Knudsen flow is that the interaction between permeate molecules and the pore surface is simply one of momentum exchange in collisions. Adsorption and desorption are assumed to be in equilibrium and surface diffusion effects are ignored. As the membrane pore diameter approaches the dimensions of the permeate molecules, these assumptions are no longer valid and the interactions between permeate molecules and the pore surfaces become significant factors in determining flux.

Surface diffusion and capillary condensation In Knudsen flow of a gas mixture, a component with a higher molecular weight and with higher polarity and polarizability will tend to be preferentially adsorbed onto the pore surface (Figure 8.4). This will increase the permeation rate of the adsorbed component by adding a surface diffusion flux to the Knudsen diffusion flux. Selectivity can also be increased, since the adsorbed species can substantially reduce the pore space available for diffusion of other components, particularly if the pore size is in the range two to three times the kinetic diameter of the adsorbed species. Surface effects can be promoted by modifying pore surfaces, for example, by the addition of functional groups that promote adsorption. If adsorption continues beyond a monolayer, capillary condensation can take place (Figure 8.4). Ultimately the pores may become blocked with the condensate

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Feed

Permeate Surface diffusion

Capillary condensation

Figure 8.4 Surface diffusion and capillary condensation effects.

Feed

Permeate

Figure 8.5 Molecular sieving.

and diffusion of other gas components will be prevented, substantially increasing selectivity.

Molecular sieving Molecular sieving is the process that takes over from Knudsen flow when the pore diameter approaches the diameter of the molecules attempting to pass through a porous membrane (Figure 8.5). Molecular sieves are materials with pore sizes of molecular dimensions within which, ignoring surface effects, selectivity is a function of molecular size, with smaller molecular species having higher diffusion rates. In molecular sieve studies, permeate molecules are commonly known as “guest” molecules. At this scale, neither the pore walls nor the guest molecules can be considered rigid; thermal vibration of the lattice structure of the membrane material and of the guest molecule will give both a degree of flexibility. The effective size of a hydrogen, nitrogen, or CO2 molecule is determined by a combination of the bond length between the constituent atoms plus the Van der Waal’s radius, which characterizes the range of the electron cloud surrounding each atomic nucleus

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Table 8.4 Common molecular dimensions Element

Bond length ˚ 5 10210 m) (A

Van der Waal’s ˚) radius (A

Kinetic diameter ˚) (dm A

Hydrogen Nitrogen Oxygen CO2 Methane H2O

1.97 1.04 1.21 1.42 (single bond) 1.09 (single bond) 0.96 (single bond)

1.20 1.55 1.52 1.70 (carbon) 2.00 3.12

2.89 3.64 3.46 3.35 3.80 2.65

Table 8.5 Comparison of molecular sieve materials Material

Description

Example applications

Zeolite

Microporous aluminosilicate minerals with well-defined pore ˚, sizes in the range 3
13 A determined by the specific chemical composition and crystal structure. Selectivity can be manipulated over a wide range by modifying the structure and chemistry of synthetic zeolites Activated carbon is an amorphous, disordered network of graphitic carbon platelets with interstitial spaces due to the presence of cross-linking chains of carbon atoms and foreign atoms between the layers. Carbon molecular sieves (CMS) use activated carbon with a molecular-scale pore network Microporous silica (pore diameter ˚ ) deposited on a mesoporous B3 A alumina or mixed-metal oxide support

˚ Hydrogen separation for 3 A and CO2/N2 or CO2/CH4 ˚ sieves separation for 4 A

Activated carbon

Composite silica
alumina or mixed-metal oxide (e.g., Mg-Al-O)

H2/CO2 separation from water
gas shift (WGS) reaction products in gasification process. Oxygen separation from air using CMS and pressure swing adsorption

H2/CO2 separation from WGS reaction products in gasification process

(Table 8.4). The size of a guest molecule is characterized by its minimum diameter when in an equilibrium state and is known as the minimum kinetic diameter. Some important examples of molecular sieve materials, zeolite, activated carbon (carbon molecular sieves (CMS)), and microporous silica are compared in Table 8.5.

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Transport of gas molecules through the tortuous pore network of a molecular sieve takes place through a combination of diffusion within the pore space and adsorption and surface diffusion on the pore surfaces. Adsorbed gas atoms or molecules (called adatoms or adparticles) diffuse on the pore surfaces (surface diffusion) down the concentration gradient between the upstream (feed) and downstream (permeate) sides of the membrane. These surface diffusion effects will be important only at lower temperatures since adsorption will no longer occur once the thermal energy of the gas molecule exceeds the heat of adsorption. For a binary gas mixture, diffusivity within the pores will be dependent on the molecular sizes. If the adsorption strengths of the two species are similar, the membrane will be selective for the smaller molecule. However, if molecular sizes are similar, selectivity will be driven by adsorption strength, since the component with the higher adsorption strength will dominate the available adsorption sites and the surface diffusion contribution to permeate flux. Among gases important for CCS (CO2, N2, CH4, H2), CO2 has the highest heat of adsorption onto zeolites and other minerals with polar surfaces, and membranes made of these materials are therefore selective for CO2 at low temperatures. If adjacent adsorption sites are separated by an energy barrier, as is the case for many adsorbates on zeolite, an activation energy is required to enable an adparticle to hop from one adsorption site to another. This variant of surface diffusion is known as activated diffusion. Another example of activated diffusion is the passage of a guest molecule through a pore aperture that is the same size as or slightly smaller than the diameter of the diffusing molecule. Multicomponent, multiphase transport through a molecular sieve, including surface diffusion, is described mathematically using the Maxwell
Stefan formulation, which accounts for both membrane
guest and guest1
guest2 interactions. An example of guest1
guest2 interactions is the competitive adsorption effect. This occurs when the available adsorption sites become saturated by the most strongly adsorbing component, blocking the transport of the other component either due to the lack of adsorption sites or because the adsorbed layers reduce the free pore size below the kinetic diameter of the second component. When simplified for a single component, the Maxwell
Stefan expression for surface diffusivity is also known as the Darken equation and gives the flux due to surface diffusion in the form: JS ðTÞBρqsat D0S ð0Þð12θÞ21 expð2 ED;S =RTÞdθ=dx

(8.7)

where JS is the flux due to surface diffusion at temperature T, ρ is the density of the membrane material, qsat is the saturated molar volume of gas adsorbed by the membrane, DS0(0) is the limiting surface diffusivity, θ is the fraction of available adsorption sites that are occupied, ED,S is the surface diffusion activation energy, R is the gas constant, and x is the linear dimension parallel to the flow through the membrane. The dependence of permeance and selectivity of a molecular sieve on the surface interactions between the guest molecule and the pore surfaces opens up the

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opportunity to achieve increased selectivity and permeance by “nano-engineering” the pore surfaces to increase the surface diffusion rate of the desired permeate. Synthetic zeolites have been widely investigated in this respect since the ionic properties of the surface can be controlled by varying the composition of the zeolite. Some examples of the CO2/N2 selectivity and CO2 permeance for these ionexchange zeolite molecular sieve membranes in the temperature range of 35
40 C are shown in Table 8.6, and illustrate the generally inverse relationship between permeance and selectivity for a particular material type. The molecular sieve with pore diameters of a few Angstroms is the finest form of microporous membrane. As pore sizes reduce further, and finally disappear, the transport process that takes over in a non-porous membrane—solution
diffusion— is a far simpler process than the complex, surface-mediated adsorption
surface diffusion occurring in the finest-scale porous membranes.

8.1.2 Solution
diffusion transport process Gas separation using non-porous membranes occurs in a two-step process in which the permeate first dissolves into the membrane and then diffuses through it (Figure 8.6). Hydrogen separation using a dense metal membrane is one such example, with adsorption of hydrogen on the feed side of the metal membrane surface Table 8.6 Zeolite ion-exchange membranes: CO2
N2 molecular sieving performance Material

CO2/N2 selectivity

CO2 permeance (mol m22s21Pa21)

Li(20%)Y LiY K(62%)Y KY

10 4 39 30

7 3 1027 2 3 1026 5 3 1027 1.4 3 1026

Feed

Permeate

Figure 8.6 Solution
diffusion transport process.

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followed by dissociation of hydrogen molecules and diffusion of protons in the membrane lattice. Hydrogen molecules are then regenerated on the permeate side of the membrane and desorbed into the permeate stream. The effectiveness of the solution
diffusion process is determined by how well the permeate (e.g., CO2 or hydrogen) is absorbed into the membrane and then how fast it diffuses through it. The solubility of the permeate in the membrane is controlled by Henry’s law, which states that, at a given temperature, the amount of a gas dissolved in unit volume of a medium is proportional to the partial pressure of the gas in equilibrium with the medium. This is expressed for permeate component i as: Ci 5 Pi =KHi 5 Pi Ki

(8.8)

where Ci is the dissolved concentration, Pi is the partial pressure, KHi is the Henry’s law constant, and Ki is the solubility of component i. Considering CO2 separation, the gas solubility (KCO2) is expressed as: KCO2 5 CCO2 =PCO2 5 1=KHCO2

(8.9)

Diffusion through a non-porous membrane is governed by Fick’s first law of diffusion, which states, again considering CO2 separation, that: JCO2 5 DCO2 ΔCCO2 =L

(8.10)

where JCO2 is the flux of CO2 through unit area of the membrane, DCO2 is the diffusion coefficient or diffusivity of CO2 in the membrane, and ΔCCO2 is the difference in CO2 concentration in the membrane between the upstream and downstream surfaces. Replacing ΔCCO2 using Equation (8.9) gives: JCO2 5 KCO2 DCO2 ΔPCO2 =L

(8.11)

where ΔPCO2 is the difference in CO2 partial pressure across the membrane. The product of solubility and diffusivity is the permeability of the membrane to the molecular component under consideration. Other gases in the feed stream will also dissolve in and diffuse through the membrane, depending on their specific solubility and diffusivity. The ratio of the flux rates for two components i and k is known as the selectivity of the membrane: αi=k 5 Ji =Jk

(8.12)

Polymeric membranes are an important class of non-porous membranes operating through the solution
diffusion mechanism and typically consist of a thin dense selective layer supported by a less dense, porous, and therefore non-selective supporting layer (Section 8.2.1). The thinness of the selective layer is dictated by the

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need to maximize permeance (and therefore flux through the membrane) and to minimize cost (the selective layer being high cost due to the customized materials and preparation requirements). The performance of polymeric membranes can be enhanced by increasing the solubility and diffusion rate of the desired permeate. Solubility is controlled by changing the chemical composition of the polymeric material, while diffusion rate is controlled by changing the physical packing of polymer within the membrane—a characteristic that is strongly dependent on the method of membrane fabrication. Very high selectivities can be achieved by these means but can be sustained only at relatively low temperatures, typically up to B100 C. The physical arrangement of polymers within the membrane depends on whether the operating temperature of the membrane is above or below the glass transition temperature of the membrane material (Tg, see Glossary). Polymeric membranes operating above Tg are termed rubbery and are flexible and generally of higher permeability and lower selectivity. Although hybrid (polymer 1 inorganic) membranes have been reported operating at up to 400 C, the rapid drop in selectivity with increasing temperature above Tg imposes a limit on the applicability of many polymeric membranes. Below Tg, polymeric membranes are glassy, hard, and less permeable, but also have microscopic voids between the polymer chains as a result of imperfect packing. This excess free volume has an important effect on the performance of glassy membranes as a result of increased solubility due to adsorption of the permeate onto the void surfaces. This adsorption is described by Langmuir’s adsorption equation: CLi 5 Cmax:i ai Pi =ð1 1 ai Pi Þ

(8.13)

where CLi is the adsorbed concentration on the microvoid surfaces, Cmax.i is the maximum adsorbed concentration, ai is the Langmuir adsorption constant, and Pi is the partial pressure of component i. The total bulk concentration, from Equations (8.8) and (8.13), is therefore: Ci 5 Pi Ki 1 Cmax:i ai Pi =ð1 1 ai Pi Þ

(8.14)

Glassy and rubbery materials have also been combined in composite polymeric (copolymer) membranes, which aim to exploit the selectivity of glassy polymers and the permeability of rubbery polymers to optimize overall membrane performance. Sections 8.5
8.7 describe a number of polymeric membrane applications and developments. Non-porous dense ceramic metal oxide membranes based on solution
diffusion have also been investigated for CO2 separation at high temperatures. Oxides such as Li2ZrO3 are particularly suitable, having high CO2 adsorption capacity (0.1 kg/kg at 600 C and PCO2 5 70 kPa) and negligible absorption of other gases such as hydrogen.

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Carbon Capture and Storage

8.1.3 Mixed matrix membranes In mixed matrix membranes (MMMs) two or more materials with dissimilar properties are combined with the aim of creating new materials which display the best features of the component materials. Polymers, either glassy or rubbery, have typically been used as the continuous phase with a variety of different embedded particles, including zeolites and ZIFs, CMS and nanotubes, mesoporous and dense silica, mixed-metal oxides, and MOFs (Figure 8.7). The pioneering work on MMMs was performed in the 1970s and involved molecular sieve particles (5A zeolite) incorporated into rubbery polymers. Transport through the membrane involves a combination of Knudsen diffusion in the molecular sieve component and solution
diffusion in the polymer component. The main fabrication challenge is to ensure that the sieving particles are well bonded with the polymer to avoid microcavities within the membrane, which can result in a loss of selectivity. In addition to the wide range of individual filler particles noted above, binary combinations of particles have also been investigated, including mesoporous silica 1 mixed-metal oxides and zeolite 1 ZIFs. This approach has a number of advantages, including improved dispersion of particles within the matrix during fabrication, higher permeability and selectivity, and the potential to engineer multifunctional MMMs for separation of multiple components from gas streams. Going one step further, ternary MMMs incorporate a third component, typically a low-molecular-weight organic additive, that improves the bonding between matrix and filler particles and fills any void space, with the aim of further improving membrane permeability and selectivity.

8.1.4 Facilitated transport membranes The solution
diffusion process described above is an example of a passive membrane transport mechanism, in which the permeate travels by diffusion down a concentration gradient. The application of membranes based on this process is often

Selective outer layer

Porous support fiber

Polymer matrix Cross section of an asymmetric composite hollow fiber

Figure 8.7 Mixed matrix hollow-fiber membrane structure.

Molecular sieving phase: zeolite or carbon molecular sieve particles

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199

constrained by low permeate flux rates due to a combination of low solubility and/ or low diffusivity. In contrast, facilitated, or carrier-assisted, transport is an active transport mechanism that increases flux rate by transporting the permeate across the membrane attached to a carrier. Many biological processes rely on facilitated transport across cell walls, and in principle facilitated transport can enable the permeate to move against a concentration gradient (from a region of low concentration to one of high concentration). In facilitated transport, the permeate reacts with a component present in the membrane (the carrier) to form complexes or reversible chemical reaction products at the feed side of the membrane. These complexes then diffuse across the membrane driven by a concentration gradient in the complex rather than a gradient in the permeate. At the downstream surface of the membrane the complexing process or reaction is reversed, liberating the transported component into the permeate stream. Carriers can be either fixed within the membrane structure or mobile, or a combination of both fixed and mobile may be used. Figure 8.8 illustrates the facilitated transport of CO2 across a cellulose acetate membrane containing an aqueous carbonate solution. At the feed side of the membrane, bicarbonate anions are formed by the dissolution of CO2 in water (Equation (8.15)), which is energetically aided by the presence of the mobile carbonate anion carrier:
CO2 1 H2 O 1 CO2
3 22HCO3 1 heat

(8.15)

At the permeate side of the membrane the reverse reaction occurs and CO2 is liberated. An example of a fixed carrier facilitated transport membrane for CO2 separation is shown in Figure 8.9. Here CO2 diffuses into the membrane and reacts with water and fixed amine groups, attached to the polymer backbone, to form bicarbonate ions: 1 CO2 1 H2 O 1 R2NH2 2HCO2 3 1 R2NH3

Feed side

2 HCO3−

Bicarbonate transport

(8.16)

2 HCO3−

High pressure

Low pressure H2O + CO2– 3 +

CO2

Permeate side

CO2

H2O + Carbonate transport

CO2– 3 + CO2

CO2

Figure 8.8 Facilitated transport of CO2 in a supported liquid membrane (SLM) with carbonate carrier.

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Carbon Capture and Storage

CO2 Feed side NH2

CO2 H2O

Amine carrier fixed to polymer backbone

Bicarbonate transport

NH3 H2O

Active polymer layer

HCO3− CO2 Porous support layer

Permeate side CO2

Figure 8.9 Amine facilitated transport membrane for CO2 separation.

Bicarbonate ions diffuse across the membrane between carrier sites, while protons are transported along the polymer backbone, with CO2 being released and diffusing out of the membrane at the permeate side. Secondary amines have also been investigated as carriers, the advantage being the lower binding energy and therefore faster desorption compared to primary amines. The reaction of a secondary amine (R1R2NH) with dissolved CO2 is described by a two-stage process: CO2 1 R1 R2 NH ! R1 R2 NH1 CO
2

(8.17)

The R1R2NH1CO22 reaction product is known as a zwitterion, a polar molecule that is electrically neutral but carries formal charges on the amine and oxygen. In the second step, the zwitterion donates its hydrogen atom (proton) to a second amine, forming a carbamate ion that transports CO2 across the membrane:
1 R1 R2 NH1 CO
2 1 R1 R2 NH ! R1 R2 NCO2 1 R1 R2 NH2

(8.18)

The reverse reactions take place on desorption at the permeate side of the membrane. Amine-based compounds, including ethylenediamine and amino acid salts, such as potassium, lithium, and piperazine glycinate, have also been investigated as mobile carriers, either alone or in combination with fixed amine carriers. Several examples of facilitated transport are summarized in Table 8.7. The permeability and selectivity values shown in the table illustrate the range of experimental results that have been achieved by varying the carrier chemistry for a given polymer type. The “Barrer” is a commonly used unit for membrane permeability and is equal to 3.4 3 10216 mol m21s21Pa21.

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Table 8.7 Experimental facilitated transport membrane performance Membrane type: Facilitator

Experimental conditions

CO2 permeability (Barrer)

CO2/X selectivity

Cellulose acetate: Pure water

CO2 1 O2, 20 C, 4 kPa CO2 1 O2, 20 C, 4 kPa 90% N2, 10% CO2, 20 C, 98 kPa 90% N2, 10% CO2, 20 C, 98 kPa

400

22 (CO2/O2)

2000 6100

600
800 (CO2/O2) 317 (CO2/N2)

2400

1417 (CO2/N2)

40/20/40 H2/CO2/N2, 20 C, 200 kPa 40/20/40 H2/CO2/N2, 20 C, 200 kPa

194

28 (CO2/H2)

338

1782 (CO2/H2)

80% N2, 20% CO2, 57 C, 10 kPa

110

210 (CO2/N2)

Cellulose acetate: 2N KHCO3 1 0.5N NaAsO2 Vinyl alcohol
acrylate copolymer: 2N K2CO3 Vinyl alcohol
acrylate copolymer: 2N K2CO3 1 0.5N EDTA Polyvinylalcohol: Glycine 1 polyethylenimine Polyvinylalcohol (cross-linked formaldehyde): Dimethylglycine 1 polyethylenimine 1 KOH Polyethersulphone: Polyvinylamine 1 amino acid salts

Pressurized air feed (10–30 MPa, 800–900°C)

e−

Oxygen ion lattice vacancies Oxygen ion conduction Return electron conduction

O2 depleted retentate

O2

O2 O+

e−

e−

O+

O+ O+

O+ O+ e− Recombined O2

e−

e− O2

Permeate

Figure 8.10 Schematic oxygen ion transport in a metal oxide lattice.

8.1.5 Ion transport membranes Ion transport membranes, also known as ion-exchange membranes or mixed conducting membranes, are a class of facilitated transport membranes in which selective transport of ionic species is achieved as a result of the structure and composition of the membrane. Figure 8.10 shows an example of an ion-exchange membrane in which oxygen ions are transported through a mixed-metal oxide lattice by jumping between oxygen vacancies in the lattice structure. The vacancies

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Carbon Capture and Storage

are in effect fixed carrier sites facilitating oxygen transport. Electrons liberated at the permeate side as the ions recombine into oxygen molecules are conducted back through the matrix to maintain electrical neutrality. A high electrical conductivity is therefore a desired characteristic for such a membrane. Minerals such as perovskite (see Glossary) and synthetic perovskite-like ceramics are suitable for this type of membrane and can be engineered for selectivity and permeability by changing the stoichiometric ratios of the metal components and oxygen vacancies. These materials have the advantage of very hightemperature operation (in the range 700
900 C) and are under development for use in syngas generation (Section 8.4) and oxygen separation for oxycombustion (Section 8.5). In the latter application the oxygen separator may be either a lowtemperature unit or a high-temperature reactor closely integrated with the combustion and heat cycle. Dual ion-exchange membranes have also been investigated for CO2 separation, with CO2 transported as a carbonate ion (CO322) within a mixed Li/Na/K carbonate phase which is molten at the high operating temperature of the membrane. This class of membranes are also known as dual phase membranes, since the molten carbonate is supported in a solid metal or ceramic framework. Formation of the carbonate ion requires the presence of oxygen in the feed gas stream. In the case of a mixed electron carbonate conductor (MECC) the second ion-exchange process is the return of the excess electrons, typically through a stainless steel or silver framework, or in a mixed oxide carbonate conductor (MOCC), an oxygen ion (O22) is returned in the second exchange process through a ceramic mixed-metal oxide (e.g., Bi1.5Y0.3Sm0.2O3, a.k.a. BYS). A molten carbonate MOCC dual ion-exchange membrane being developed to enable CO2 separation from high-temperature and highpressure streams in power generation applications such as syngas production or integrated gasification combined cycle (IGCC) is described further in Section 8.6.

8.1.6 Supported liquid membranes Immobilized or supported liquid membranes (SLMs) are membranes in which a liquid is immobilized by capillary pressure within the pore space of a support material, and in which gas permeation occurs typically by the solution
diffusion mechanism. A wide variety of support materials have been tested, including alumina and titanium oxide, polytetrafluoroethylene (PTFE), mesoporous carbon, ZIFs and MOFs, while liquids most commonly employed in SLMs have been amine-based solvents, such as diethylenetriamine, diaminoethane, and diglycolamine. More recently ionic liquids (see Section 6.3.3) have been investigated as sorbents in supported ionic liquid membranes (SILMs), having the dual advantages of low vapor pressure and high viscosity, which can reduce liquid loss from the membrane either through evaporation or expulsion due to a high transmembrane differential pressure. In the case of SILMs using functionalized or task-specific ILs (Section 6.3.3), the amine functional groups introduce a facilitated transport mechanism of the type illustrated in Figure 8.9, alongside the solution
diffusion mechanism.

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203

The combination of ILs, which can be tailored by selection of a variety of cations and anions, with different membrane types (thin film composite, mixed matrix, etc.) provides a fertile field for generating novel membranes with enhanced properties. Current areas of research in SLMs include: G

G

G

Alternative functional groups that can enhance gas separation, for example, through phase-change behavior Methods to prepare composite membranes with an ultrathin SIL layer on a highly permeable support, to improve gas permeability while retaining high selectivity Improved stability at realistic operating conditions

Molecular gate membranes A novel combination of supported liquid and facilitated transport mechanisms has been exploited in the development of molecular gate membranes which show promise for CO2/H2 separation in pre-combustion applications (Kai et al., 2017). These are a type of polymeric membranes in which a dendrimer (see Glossary) such as poly(amidoamine) (PAMAM), which is a room temperature liquid, is immobilized in a polymeric network. Typically in polymer membranes, the solution:diffusion process gives little or no CO2/H2 selectivity—CO2 being more soluble but H2 having higher diffusivity due to its smaller size. However, in a molecular gate membrane, CO2 reacts with the amine groups forming bicarbonate or carbamate ions which facilitate the transport of CO2 across the membrane while at the same time reducing its permeability to H2 by 10- to 100-fold, depending on the dendrimer content (20
50 wt%).

8.2

Membrane configuration and preparation, and module construction

With the exception of natural gas processing, the use of membrane technology for CCS gas separation applications is still confined to the laboratory scale. Thus, as well as the physical and chemical investigation and optimization of membrane materials, the eventual application of membranes for CCS on an industrial scale will also require the further development of technologies for fabricating reliable and economical membrane modules. The main challenges are as follows: 1. Reducing the thickness of the membrane selective layer to increase flux and reduce cost, while preserving selectivity 2. The large-scale production of defect-free membranes with the desired physical and chemical properties 3. Automation of membrane and module fabrication processes to cost-effectively package the membrane into reliable modules, achieving maximum membrane surface area within a given module size

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Carbon Capture and Storage

Other challenges to be addressed as membrane systems are developed toward commercial deployment include chemical and mechanical compatibility and stability within the industrial process environment, to give a commercially viable membrane lifetime, and plant-level analysis to optimize system configuration and operating parameters, and cost versus performance trade-offs. Methods for industrial-scale preparation of membranes and fabrication of modules have been developed since the 1960s, driven by applications in reverse osmosis for water purification and desalination. Many of these techniques are directly applicable to gas separation problems (e.g., hollow-fiber modules are applied in reverse osmosis as well as in natural gas sweetening), but novel membrane materials and applications in CCS will also require new developments in this area. In this section membrane preparation and module fabrication methods are described, with reference to specific applications and the current areas of technology development.

8.2.1 Membrane types Membrane preparation methods and suitable module configurations are strongly tied to the required structure of the membrane material. Several types of membrane structure can be identified, as shown in Figure 8.11, the main features of these structures being summarized in Table 8.8. (See Loeb, 1981 for a fascinating account of the origin of the Loeb-Sourirajan membrane, which was central to the development of desalination by reverse osmosis.) Most non-liquid membranes, whether polymeric, ceramic, or metallic, can be prepared as either symmetric or asymmetric structures. However, optimization for high flux rate generally drives toward asymmetric structures with a thinner selective surface combined with a thicker, non-selective supporting layer. Zeolite membranes are an example of asymmetric membranes and are typically prepared by in situ hydrothermal synthesis of a thin zeolite layer onto support tubes or disks of porous stainless steel or alumina. Non-porous membrane

Porous membrane

Loeb-Sourirajan membrane

Thin film composite membrane

Isotropic membranes

Anisotropic membranes

Figure 8.11 Physical structure of membranes.

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205

Table 8.8 Structural characteristics of membranes Structure

Characteristics

Symmetric (or isotropic) membranes Asymmetric (or anisotropic) membranes

Porous or dense non-porous membranes with a uniform structure throughout the membrane thickness Porous or dense non-porous membranes with a thin selective layer either bonded to a thicker layer that provides mechanical support (thin film composite membrane) or resulting from the specific membrane preparation process (Loeb-Sourirajan membrane) A liquid selective phase, supported, contained, or immobilized within the pore space of a polymeric or ceramic membrane

Liquid membranes

Table 8.9 Area-to-volume ratios for various membrane configurations Module configuration

Typical area-to-volume ratios (m2/m3)

Plate and frame Spiral wound Hollow fiber

200 500
1000 1500
10,000

8.2.2 Membrane module configurations Symmetric or asymmetric membranes can be prepared either as laminar membranes, as hollow tubes or fibers, or as wafers and packaged in a variety of different module configurations. The earliest module designs consisted of flat sheets of membrane material held in a frame (plate-and-frame modules) or bundles of relatively large diameter (1
3 cm) tubes (tubular modules). This module design does not in general provide the high surface area to bulk volume ratio required for gas separation applications (Table 8.9), and current commercially available gas separation modules use either spiral-wound or hollow-fiber modules.

Spiral-wound modules Spiral-wound membrane modules consist of a number of membrane envelopes wound onto a central perforated collecting tube. Each membrane envelope, or leaf, consists of two membranes separated by a permeate spacer and sealed on three sides, leaving one side open for permeate removal. Early designs used a single membrane envelope, but this requires a long spiral path to achieve a high surface area-to-volume ratio, resulting in a high-pressure drop along the spiral permeate flow path. Figure 8.12A illustrates the configuration of a spiral-wound membrane element.

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Carbon Capture and Storage

(A)

Feed

Retentate

Permeate

Feed spacer Membrane Permeate spacer Membrane Feed spacer

Spiral flow of permeate within spacer Retentate

(B)

Module housing

Membrane element

Feed Permeate

Figure 8.12 Spiral-wound membranes: (A) element configuration and (B) module construction.

The feed gas mixture flows axially along the module through feed spacers held between successive membrane leaves. The permeate passes through the membranes and then flows spirally through the space held open by the permeate spacer, exiting the open edge of the membrane leaf into the central collecting tube. The construction of spiral-wound modules in commercial production for CO2 removal from natural gas is illustrated in Figure 8.12B. Optimization for a specific application requires selection of the number of membrane leaves, module length and diameter, which determine the pressure drop, weight, and cost of the module. Weight and ease of handling are important practical considerations in view of the need to replace modules after performance degradation or failure.

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Figure 8.13 Natural gas sweetening membrane skid unit. Source: Courtesy, Membrane Technology and Research Inc.

CO2 rich feed gas Shell-side feed

Header CO2 rich permeate stream

Sweep stream Bore-side feed Hollow-fiber membrane section

CO2 lean product stream

Figure 8.14 Hollow-fiber membrane module structure.

In natural gas processing applications, typically four to six modules are mounted inside a tubular pressure vessel, and many of these tubular elements are mounted in series or parallel to form the complete membrane separation unit. Figure 8.13 shows an example of a natural gas sweetening membrane skid comprising two banks of six tubular membrane modules.

Hollow-fiber modules Hollow-fiber modules are also extensively used in natural gas treatment because of the very high surface to bulk volume ratio noted above. Modules consist of bundles of fibers enclosed in a pressure vessel, with the permeate passing either out of the fibers (bore-side feed) or into them (shell-side feed), as illustrated in Figure 8.14. Fibers are mechanically able to withstand much higher pressures applied externally than internally, so for high-pressure applications the shell-side feed configuration is used.

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Carbon Capture and Storage

Optimization of hollow-fiber modules for specific applications involves selection of the fiber diameter, and hence the packing density of fibers in the module, and the flow direction of shell versus fiber—whether these flows are co-current or counter-current. Hollow-fiber membrane separation units for gas separation are constructed in a similar manner to the spiral-wound skid unit shown in Figure 8.13. Fiber modules are commonly 1 m in length and 0.2
0.25 m in diameter, again for physical handling reasons, and contain B106 individual fibers with internal and external diameters of B50 and 100 μm. Hollow-fiber modules for gas
liquid contactors use polymer fibers, which are typically an order of magnitude larger in cross section, with inner and outer diameters of B600 and 1000 μm. Hollow-fiber-based separation units are typically smaller than those based on spiral-wound modules, although spiral-wound modules are able to handle higher operating pressures and are more resistant to fouling caused by particles in the feed gas stream that can block fine fibers.

Ceramic wafer stack modules Advanced membrane materials such as metal oxide ion transport membranes require new module structures to cope with the high operating temperatures and pressures. One example is the ceramic wafer stack configuration shown in Figure 8.15, a derivative of the early plate-and-frame type module. This module has been developed for oxygen separation for IGCC and oxyfueling applications by a US Department of Energy National Energy Technology Laboratory-funded consortium led by Ceramatec and Air Products. The module consists of a stack of wafers, each comprising a back-to-back pair of perovskite-based oxygen ion transport membranes. Air is fed into the module at 800
900 C and a pressure of 0.7
2.0 MPa and oxygen is transported through the wafers and collected from the central tube.

Dense membrane

Oxygen flowing from air through dense membrane One membrane in module

Dense, slotted backbone

Hot compressed air Porous membrane support

High purity O2 product

Figure 8.15 Ceramic membrane wafer stack module. Source: Courtesy, Air Products and Chemicals Inc.

0.5 t-O2/day module

Membrane separation systems

8.3

209

Membrane technology RD&D status

The previous sections illustrate the diverse range of membrane technologies that are available for potential CCS applications. Tables 8.10 and 8.11 summarize the main features of these membrane types and indicate the current areas of research, development, and demonstration work. The RD&D focus areas listed are not intended to be exhaustive but to give a flavor of the range of topics being investigated for each membrane type.

Table 8.10 Membrane technologies and RD&D summary: microporous membranes Membrane technology

Description

Advantages/ disadvantages

CMS membranes

Activated CMS composed of an amorphous, disordered network of graphitic carbon platelets

1 High CO2 selectivity Selection and against N2 and CH4 carbonization of precursor material to 1 Durable and highcontrol pore temperature structure; membrane operation doping to improve 2 Low CO2 permeability mechanical strength 2 Optimal precursor and reduce cracking; materials and techniques to membrane improve regeneration fabrication are and eliminate aging expensive effects (e.g., due to 2 Brittle nature and chemical thermal expansion degradation) make membrane module construction complex Optimizing 1 Perfect selectivity adsorption
diffusion and high by substituting permeability in various cations specific molecular (Li1, Na1, Ca21, K1) sieving applications into the zeolite (e.g., H2 separation) 1 Resistant to CO2 to produce induced ion-exchanged plasticization zeolite membranes and reduce H2S 2 Limited selectivity sensitivity; modify for molecules with surface properties to similar kinetic overcome water diameter (e.g., CO2, sensitivity O2, N2) 2 Water and H2S cause degradation in performance

Zeolite molecular sieve Microporous lattice membranes with well-controlled pore sizes in the ˚ range of 3
13 A

RD&D focus areas

(Continued)

210

Carbon Capture and Storage

Table 8.10 (Continued) Membrane technology

Description

Advantages/ disadvantages

RD&D focus areas

Silica membranes

Microporous membrane operating either by Knudsen diffusion or by molecular sieving and surface diffusion, depending on pore size

Hybrid membranes (e.g., amine
or polyimide
silica membranes)

Composite membranes with organic groups incorporated into the microporous silica matrix or chemically bonded to the pore surfaces to create so-called functional membrane pores

1 Chemical, thermal, Silica deposition and structural methods and stability conditions to achieve desired, defect-free 1 Structure (pore size pore structure; fineand distribution) tuning pore size (e.g., easily tailored by by deposition of preparation methods alkoxysilane and conditions monolayers) 2 Generally low selectivity 1 Increased selectivity Selection of polymers compared to a nonand alternative functional ceramic techniques to membrane as a result uniformly of the enhanced incorporate and surface diffusion of activate the the permeate functional groups in 1 Thermal and the ceramic matrix; mechanical stability optimized pore of ceramic structure of membranes composite combined with the membranes; selectivity of integration of polymers membranes with absorption or adsorption systems to reduce regeneration energy requirement

Table 8.11 Membrane technologies and RD&D summary: dense (non-porous) membranes Membrane technology

Description

Advantages/ disadvantages

RD&D focus areas

Polymeric membranes

Predominantly glassy polymer materials, of which polyimides are the most extensively investigated; also copolymer (glassy 1 rubbery) varieties, combining selectivity and permeability, and hybrid (rubbery 1

1 Thermal stability, chemical resistance, and mechanical strength of polyimide membranes

Polymer selection and preparation methods to improve mechanical strength, durability, and chemical stability and reduce plasticization tendency and manufacturing cost; polymers for higher-

1 High degree of control over permeability and selectivity through control of polymer preparation, and

(Continued)

Membrane separation systems

211

Table 8.11 (Continued) Membrane technology

Description inorganic backbone) to improve mechanical properties

Advantages/ disadvantages chemical composition, including functional groups 2 Swelling and plasticization tendency with CO2 sorption 2 Limited to relatively low-temperature applications

Mixed matrix membranes

Glassy or rubbery polymer membranes with molecular sieving particles (zeolite, activated carbon) or other micro- or nanoparticles (silica, MOFs) embedded in the polymer matrix

Fixed carrier facilitated transport membranes

Solid polymeric membranes incorporating fixed carriers that react reversibly with the permeate and increase the selectivity and permeability of the solution
diffusion transport mechanism A mobile carrier facilitated transport membrane, typically a polymeric or microporous support

Immobilized (supported) liquid facilitated transport

1 Opportunity to combine the high permeability of rubbery polymers with the selectivity of molecular sieves 2 Formation of microcavities due to poor bonding between polymer and included particles, particularly for glassy polymers 2 Poor dispersion of nanoparticles in the polymer matrix, reducing performance and mechanical strength 1 High selectivity and permeate flux 1 Less carrier loss than mobile carrier membranes 2 Lack of mobility of the functional group

1 Very high CO2 permeability and selectivity to N2 1 Low solvent inventory required

RD&D focus areas temperature applications; increasing selectivity in rubbery membranes by functional group substitution and in glassy membranes using high CO2 solubility pore-filling materials; integration with adsorption (PSA/ VSA) systems to improve energy efficiency New polymers, preparation and posttreatment methods to improve particle bonding, reduce swelling and plasticization; filler particle selection, preparation and pretreatment; combination of multiple filler particle types; use of hollowfiber membranes; large-scale pilot testing

Identification and testing of polymer
carriers combinations; membrane fabrication methods; incorporation of multiple fixed and mobile carriers to improve transport properties Reaction catalysts and other solution additives to improve separation performance;

(Continued)

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Carbon Capture and Storage

Table 8.11 (Continued) Membrane technology

Description

Advantages/ disadvantages 2 Loss of liquid through evaporation or leakage 2 Aging or degradation of the carrier due to chemical instability 2 Carrier saturation at high permeate pressure

membranes (SILMs)

containing an aqueous solution immobilized in the pore space

Metal membranes

Hydrogen-selective solution
diffusion membranes formed by depositing a micronscale metallic layer, such as palladium, onto a porous support

1 100% hydrogen selectivity 2 Low permeability 2 Poor mechanical properties and chemical degradation due to sulfur and chlorine sensitivity

Metal oxide ionexchange membranes

Dense metal oxide membranes, typically perovskite-like minerals, conducting oxygen ions by facilitated transport between oxygen vacancies in the lattice Ion exchange in a molten carbonate electrolyte, held in the pore space of a metal (MECC) or ceramic metal oxide (MOCC) structure

1 High-temperature operation 1 High O2 or CO2 absorption capacity 1 Low susceptibility to contaminant gases (SOx, H2S)

Dual-phase ionexchange membranes

1 Very-hightemperature application—close to combustion point in power generation 1 Absolute selectivity for CO2 2 Support material performance in hightemperature oxidizing environment 2 MOCC CO2 permeance typically limited by oxygen ion transport in the ceramic phase

RD&D focus areas improved carriers to reduce degradation at realistic operating conditions; fabrication methods and support structures; lowvolatility liquid selection to limit liquid loss through drying Metal alloys to improve mechanical properties and resistance to chemical degrading; membrane treatment to improve permeability; membrane and module fabrication methods Scale-up of pilot scale (5 t-O2/day) oxygen separation plant for oxycombustion

Robustness of metal framework under high-temperature oxidizing conditions (e.g., use of silver vs stainless steel); membrane composition and construction to achieve high permeance

Membrane separation systems

8.4

213

Membrane separation applications

8.4.1 Oxygen ion transport membranes for syngas production The formation of syngas (H2 1 CO) in the pre-combustion capture process described in Chapter 3, requires a supply of oxygen for the partial oxidation step. In 1988, Standard Oil Co. (subsequently Amoco and now BP) patented the Electropox (electrochemical partial oxidation) process that integrated oxygen separation, methane oxidation, and methane steam reforming into a single step. The process is based on a hollow-tube-configured ceramic oxygen transport membrane that contains the methane-plus-steam mixture and allows the passage of oxygen ions and electrons. The membrane is composed of a perovskite-like solid metal oxide material, in which the oxidation state of cations in the membrane has been altered to introduce oxygen vacancies into the structure. This allows oxygen ion transport through the membrane by a hopping mechanism between vacancies, described in Section 8.1.4. The Electropox technology has been the subject of an intensive, collaborative research and development effort since 1997, with the aim of bringing the technology to the stage of a demonstration-scale plant. Table 8.12 summarizes some of the

Table 8.12 Electropox R&D focus areas Key issue

Research tasks

Oxygen diffusion kinetics

Measurement of kinetics of oxygen uptake and transport in ceramic membrane materials under commercially relevant operating conditions Measurement of surface activation and reaction rates in ion transport membranes Evaluate the effect of defect configuration on ceramic membrane conductivity and long-term chemical and structural stability Assess the microstructure of membrane materials to evaluate the effects of vacancy
impurity association, defect clusters, and vacancy
dopant association on the membrane performance and stability Evaluate phase stability and thermal expansion of candidate perovskite membranes and develop techniques to support these materials on porous metal structures Determine material mechanical properties under conditions of high temperature and reactive atmospheres Preparation and characterization of dense ceramic oxygenpermeable membranes Design, fabrication, and evaluation of ceramic-to-metal seals based on graded ceramic powder and metal braze joints

Grain structure and atomic segregation

Phase stability and stress development Mechanical property evaluation in thermal and chemical stress fields Graded ceramic and metal seals

214

Carbon Capture and Storage

Air

Methane (CH4) Air

Retentate (N2)

Shell side

O2

2CH4 + O2 ↔ 4H2 + 2CO

Shell side

O2

Syngas (H2, CO)

Perovskite ion exchange membrane

Figure 8.16 Oxygen transport membrane application to methane partial oxidation.

key issues that have been investigated and illustrates the breadth of the R&D effort required to bring such a technology to the demonstration stage. As an example, optimization of the oxygen conductivity and stability of the membrane material involves investigating the properties of various types of mixedion electronic conductors of the general form AxA0 12xByB0 12yO32δ where A, A0 , B, and B0 are metal ions and δ indicates the oxygen non-stoichiometry (i.e., proportion of vacancies in the lattice). Here replacement of a proportion of the A-site ions (e.g., trivalent La31) by a lower-valency A0 ion (such as divalent Sr21) increases the oxygen vacancies in the lattice. One such example is La0.7Sr0.3Co0.2Fe0.8O32δ, which has exhibited high oxygen permeance combined with good chemical and mechanical stability in laboratory investigations. A similar application for oxygen ion transport membranes is in the partial oxidation of methane as an initial step in a gas-to-liquids process. As shown in Figure 8.16, this is essentially the Electropox process but with the steam reforming reaction left out. The partial oxidation reaction: 2CH4 1 O2 5 2CO 1 4H2

(8.19)

produces a syngas product stream with a stoichiometric ratio close to the ideal for the Fischer
Tropsch gas-to-liquids process, which is used to convert syngas to liquid hydrocarbons through catalyzed chemical reactions of the form: ð2n 1 1ÞH2 1 nCO ! Cn H2n12 1 nH2 O

(8.20)

As an alternative to oxygen supply from cryogenic air separation, which is capital- and energy-intensive, further developments in oxygen ion transport membranes could simplify the gas-to-liquids process and reduce production costs by 20%
30%.

8.4.2 Palladium membranes in IGCC applications Palladium (Pd) or palladium and silver (Pd/Ag) alloy metallic membranes, which are 100% selective for hydrogen, have an important potential application in IGCC power plants. A Pd-based water
gas shift membrane reactor (WGSMR) can be

Membrane separation systems

215

WGS catalyst High pressure side Syngas (H2, CO, CO2) Steam

Retentate (H2O, CO2)

CO + H2O ↔ H2 + CO2 Palladium

metal membrane

Sweep stream H2

H2

H2

H2

H2 + sweep stream

Low pressure side

Figure 8.17 Water
gas shift (WGS) membrane reactor.

used to separate hydrogen directly from the WGS reaction zone (Figure 8.17), resulting in improved efficiency of the reaction. The membrane typically consists of a thin Pd or Pd/Ag film of a few microns thickness, on a macroporous support such as a stainless steel tube. Removing hydrogen as it is formed results in more complete conversion of CO to CO2, since it prevents the shift becoming limited by equilibrium between the forward and reverse reaction (see Table 3.3). Alternatively, the reaction temperature to achieve a certain conversion rate can be reduced, thereby reducing the reactor energy requirements. Water is removed from the retentate by condensation, to leave a near-pure CO2 stream at a pressure that is close to the high operating pressure of the reactor ( . 10 MPa). This reduces the energy penalty for compression before transport and storage. Laboratory-scale WGSMRs have been demonstrated using Pd or Pd/Ag alloy membranes operating in the temperature range of 300
600 C and have achieved 100% hydrogen selectivity and almost complete CO conversion. Fabrication techniques for Pd and Pd/Ag membranes and membrane modules have also been developed (see Peters et al., 2017), an important step toward scale-up of this application. Microporous membranes (silica, alumina, carbon, and zeolite), typically asymmetric membranes on mesoporous alumina supports, have also been investigated for WSGMR applications. In this case hydrogen selectivity is the result of molecular sieving and surface diffusion through the selective layer, with pore diameters in ˚ (3
7 A ˚ for zeolite), although these membranes have lower the region of 7
20 A H2 versus CO2 selectivity than Pd-based metallic membranes.

8.4.3 Membrane and molecular sieve applications in oxyfuel combustion A 500 MW power plant using oxyfuel combustion, operating at currently achievable plant efficiency (45%), requires an oxygen supply of 8 kt-O2/day. Cryogenic air separation, discussed in Section 9.3, is the only currently commercial process for delivering oxygen at this rate, and cryogenic ASUs with capacities up to B4 kt-O2/day are installed worldwide. However, with a typical energy requirement of B200 kWh/t-O2 to deliver oxygen at 170 kPa for oxyfuel combustion

216

Carbon Capture and Storage

applications, oxygen supply alone would consume .10% of the output of an oxyfueled power plant. The IPCC threshold of 0.1 Mt-CO2/year for defining a large stationary CO2 source corresponds to a power plant of B12 MW for current efficiencies. A plant of this size would require B200 t-O2/day for oxyfuel combustion. This is close to the maximum rate currently achievable using molecular sieve
based ASUs and is in the range of oxygen production rates targeted by technology development work for membrane-based oxygen production.

Molecular sieves for oxygen production The industrial separation of air into oxygen and nitrogen by pressure swing or vacuum and pressure swing adsorption, discussed in Chapter 7, is an established application of carbon and zeolite molecular sieves. CMS have very similar capacities of adsorption for oxygen and nitrogen, but the rates of adsorption of these two species differ significantly, oxygen adsorption being considerably faster than nitrogen adsorption. Separation of oxygen and nitrogen by pressure swing adsorption therefore results from the difference between the rates of adsorption of the two species. When a CMS comes into contact with air, the adsorbed phase becomes oxygen-rich while the gaseous phase becomes correspondingly nitrogen-rich. This difference is related ˚ ) compared to that to molecular size, the smaller kinetic diameter of oxygen (3.46 A ˚ ) resulting in faster adsorption into the activated carbon surface. of nitrogen (3.64 A The CMS pressure swing adsorption (CMS-PSA) process is widely used for nitrogen generation with, in this case, the adsorbed oxygen being vented back to the atmosphere during the sorbent regeneration part of the PSA cycle. Alternatively, the released oxygen can be captured and the process used for oxygen generation. Pressure swing absorption units can yield an oxygen stream with 95% purity, with plant capacities up to 200 t-O2/day.

Ion transport membranes for oxygen production Ion transport membranes have been the subject of an extensive RD&D project since 1999, partly funded by the US Department of Energy National Energy Technology Laboratory, and a 5 t-O2/day prototype unit (shown in Figure 8.18) started operation in 2005. The perovskite-based metal oxide ion transport membrane modules have a wafer stack configuration (Section 8.2), and multiple modules are housed within the high-pressure membrane vessel. The plant delivers a .99% pure oxygen permeate stream and has successfully demonstrated that this technology can be applied on a commercial scale. This technology reduces the energy cost of oxygen production by one-third compared to cryogenic methods. An intermediate-scale pilot capable of producing 100 t-O2/day has been constructed and tested but future development work, which aimed to scale up the capacity to in excess of 1000 t-O2/day, was terminated in 2015.

Membrane separation systems

217

Control room Heater

Vacuum pumps

Recycle compressor

Membrane vessel

Heat exchangers

0.5 t-O2 /day

Figure 8.18 Prototype 5 t-O2/day ITM oxygen separation plant. Source: Courtesy Air Products.

8.4.4 Membrane applications in post-combustion CO2 separation Membrane separation of CO2 from flue gases is a very active research field, which aims to reduce the energy penalty and cost of membranes to enable large-scale demonstration and deployment. The key characteristics that need to be combined in a commercial membrane are as follows: G

G

G

Sufficient permeate flux rate to achieve desired operating throughput Low space requirements and capital cost, including membrane material cost Low sorption capacity for non-selected gases (typically N2, CH4, and H2)

218

G

G

G

Carbon Capture and Storage

Chemical resistance to contaminants (SOx, NOx, H2O, H2S) Thermal stability at required operating temperature Inexpensive fabrication methods for a variety of module configurations

Achieving a combination of sufficient selectivity, to yield high CO2 purity in the permeate stream, with high permeability, to give a high flow rate without excessive pressure drop, is the key to unlocking the potential of membranes for CO2 separation from high-volume flue gases. The most advanced membrane-based pilot for post-combustion capture is a 1 t-CO2/day facility installed in 2012 at the US DOE’s National Carbon Capture Center, processing a flue gas slipstream from Alabama Power’s E. C. Gaston coalfired plant in Wilsonville, AL. The systems use a proprietary polymer membrane developed by Membrane Technology Research (MTR Polarist) in spiral wound modules (see White et al., 2015). The tested process configuration includes two membrane separation stages, as illustrated in Figure 8.19. In the first stage, CO2 is drawn through the membrane by a vacuum pump, yielding a 70% CO2 permeate stream which would be further processed by dehydration, compression, and chilling to yield scCO2 for sequestration. In the second stage, CO2 permeate is swept by a countercurrent air flow, and the resulting 8% CO2 permeate stream is recycled to the coal-fired boiler, boosting the flue gas CO2 content from the 13%
14% typical for air drafted boilers to 20%. Following extensive pilot testing from 2012 to 2014, a 20 t-CO2/day demonstration-scale plant began operation at the same facility in 2015. A commercial deployment at a 600 MWe scale is expected to require a membrane area of between 1 and 3 3 106 m2, depending on the process configuration, with a cost of carbon avoided in the region of $20
25/t-CO2. Other membrane technologies under development for post-combustion capture are described in the following sections.

Air sweep + 8% CO2 recycle Air sweep

First-stage Compressor crossflow module 20% CO2

Particulate removal

CO2

CO2

10% CO2

Boiler

70% CO2

Coal fuel

Vacuum pump

CO2

CO2

Second-stage countercurrent sweep module

Dehydration Compression

Flue gas to vent 2% CO2

N2 to vent

CO2 to storage

Figure 8.19 Two-stage membrane separation system for post-combustion capture.

Membrane separation systems

219

High-temperature molten carbonate membrane A dual ion-conduction membrane using a molten carbonate is under development for high-temperature and high-pressure CO2 separation from flue gas streams close to the point of combustion, or to remove CO2 from a syngas stream after the production of hydrogen in the WGS reaction. The membrane, illustrated in Figure 8.20, is based on a composite material that combines oxygen ion exchange through a solid metal oxide with CO2 transport as a carbonate anion (CO22 3 ) through the molten carbonate phase. At the feed surface of the membrane, an oxygen anion from the metal oxide combines with CO2 to form a carbonate anion: CO2 1 O2
! CO2
3

(8.21)

This ion is transported through the molten carbonate electrolyte, which is immobilized in the pores of a metal or mixed-metal oxide matrix (e.g., silver oxide and perovskite). At the permeate side, the carbonate anion releases CO2 into the gas phase while the oxygen ion enters a lattice vacancy in the metal oxide and is transported back to the feed side, driven by the gradient in vacancies within the metal oxide lattice. Current R&D efforts focus on identification and testing of alternative metal oxide compositions to optimize CO2 perm-selectivity, surface modification (e.g., alumina coating) of metal oxide matrix to improve performance, and on varying fabrication methods to control the volume fractions and pore structure of the composite material.

Feed N2

CO2

Molten carbonate O+ O+

N2

CO2

O+

O+

O-

N2

+ O- O

O+

O-

O-

O+

O+ O

|

N2

O– |

CO2 O+ O+ O+ O+

-

CO2

O+

O+

O– - CO2

Carbonate ion transport O–

O+

O+

O+

- O–

N2

N2

O+O -

O

O+

O+ O+

CO2

O-

O+

CO2

Oxygen ion transport +

O+ O+

O+

O+ O+

|

CO2 O+

O–

O–

O–

|

Solid oxide +

O O+

CO2

|

CO2

CO2

CO2

O+ O+ O+

O+

CO2

Figure 8.20 Molten carbonate high-temperature dual ion-exchange membrane.

220

Carbon Capture and Storage

Facilitated transport membranes A wide variety of different membrane material and functional group combinations have been tested for application in post-combustion separation, a typical example being amine carriers in a cross-linked polyvinyl alcohol polymer membrane. The membrane showed good CO2 permeability and CO2 and N2 selectivity at operating temperatures up to 170 C. Mathematical modeling studies indicated that a 0.6 m long hollow-fiber module containing B106 fibers could recover . 95% of the CO2 from a 0.5 m3/s flue gas stream into a 98% CO2 permeate stream, yielding B12 tCO2/day per module. At this rate, B800 modules would be required to process the B1.4 3 106 m3/h of flue gas from a 500 MW coal-fired power plant. A polyvinylamine (PVAm) fixed carrier membrane has also been tested in a small-scale pilot as part of the EU-funded Nanoglowa project. A plate-and-frame membrane module containing 1.5 m2 of the PVAm membrane was tested at the EDP’s 314 MWe coal-fired power plant in Sines, Portugal, processing a 24 m3/h flue gas slipstream and producing a 75% CO2 permeate stream. The permeability (88
266 Barrer) and CO2/N2 selectivity (80
300) are similar to other facilitated transport membranes summarized in Table 8.7.

CMS membranes CMS membranes hold promise for flue gas CO2 separation applications because of their high thermal and chemical stability in non-oxidizing environments, essential characteristics for this application. Although high selectivity for CO2/N2 ( .100) and CO2/CH3 ( . 250) have been demonstrated in laboratory experiments, these have been achieved only at very low permeabilities in the range from 1 to 10 Barrer (3
30 3 10216 mol m21s21Pa21). Current research efforts for this type of membrane are focusing on: G

G

G

G

G

Selection, preparation, and pre-treatment of the precursor material to reduce the cost of membrane production Parameters of the carbonization process (temperature, heating rate, pyrolysis atmosphere) to control the membrane pore structure Post-carbonization treatment of the membrane, for example, additional carbon deposition by chemical vapor deposition Membrane doping to improve mechanical strength and reduce cracking Techniques to improve regeneration and eliminate aging effects, for example, due to chemical degradation

8.4.5 Membrane applications in natural gas processing The removal of CO2 from natural gas or natural gas liquids is important in order to deliver hydrocarbon products to a low CO2 sales specification and to reduce the potential for corrosion of process equipment, pipelines, and product distribution systems.

Membrane separation systems

221

Polymeric membranes Polymeric membranes have been in use for CO2 removal from natural gas since the early 1980s and many systems are operating around the world, most commonly using spiral-wound or hollow-fiber cellulose acetate-based asymmetric polymer membranes. Feed gas pre-treatment removes heavy hydrocarbon components and particulate contaminants that can cause fouling of the membrane modules. While CO2 can also be easily separated from methane and from propane and heavier components (C31) using traditional distillation columns (Section 9.2), the separation of CO2 from ethane is problematic due to the closeness of their vapor pressures and due to the formation of an azeotrope (see Glossary) between CO2 and ethane. This azeotrope has an approximate composition of 70% CO2 and 30% ethane at ambient temperature and prevents further CO2
ethane separation by simple distillation. A pilot-scale (B400 m3/day) membrane separation plant has been demonstrated by BP for CO2 separation from liquid ethane. The plant used a commercially available Cameron/NATCO-Cynarat asymmetric cellulose acetate hollow-fiber membrane module, with a shell-side feed of liquid ethane and dissolved CO2. Methane was used as the sweep gas on the boreside of the module, necessitating a further CH4:CO2 separation stage. Statoil and UOP have also demonstrated a hybrid distillation
membrane system in the Ka˚rstø Ethane Plant, in which the membrane is used to break the CO2
ethane azeotrope, maximizing ethane recovery and producing a high-purity CO2 stream. A feed gas stream comprising 82% ethane, 16% CO2, 1% methane, and 1% C31 from the ethane plant is distilled in a chilled CO2 stripping column, yielding an ethane bottom stream and an azeotrope-limited CO2 1 ethane top stream (Figure 8.21). This stream enters a membrane separator consisting of spiral-wound asymmetric cellulose acetate membrane modules, where the azeotrope is broken by differential

Low-grade fuel (CO2, CH4, C2H6) Feed Retentate

Ethane, CO2 CO2 stripper (–5°C)

CO2 stripper

Membrane separator CO2 purification (–30°C)

Ethane Permeate compressor

Liquid CO2

Figure 8.21 Hybrid membrane
distillation process for CO2
ethane separation.

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Carbon Capture and Storage

Natural gas dew-pointing stream

Natural gas

CA membrane

Dual membrane module

CO2 to EOR flood

Rectification

Feed

Separator

Heater

PDMS membrane

Heater Light hydrocarbons

Figure 8.22 Dual membrane module system for EOR production processing.

transport across the membrane. Both permeate and retentate streams are then purified in second-stage chilled distillation columns, recovering overall 98% of the feed stream ethane in a 95%-pure ethane product, and 78% of the feed CO2 in a 99.98%-pure CO2 product. A dual membrane system employing polymeric membranes has also been proposed to separate CO2 from light hydrocarbons in CO2 flooding EOR operations, as illustrated in Figure 8.22. The membrane module consists of two membranes sharing a common feed—a cellulose acetate membrane producing a CO2 permeate stream and a poly(dimethylsiloxane) (PDMS or silicone) membrane producing a light hydrocarbon stream, with methane at the retentate. Since PDMS also has high CO2 permeability, the PDMS permeate stream is recycled. In hydrocarbon processing, rectification refers to the purification of a product stream (in this case the light hydrocarbon stream) by distillation.

Polymeric facilitated transport membranes Polymeric immobilized liquid membranes (ILMs) have also been investigated for CO2
ethane separation. Diethanolamine and polyethylene glycol solutions have been investigated as ILM solvents and have shown increased CO2 permeance and selectivity over non-facilitated polymeric membranes. One problem with this type of membrane is the saturation of the carrier at higher CO2 partial pressure, which imposes a fundamental limit on CO2 transport across the membrane.

Gas
liquid membrane contactors Gas
liquid membrane contactors make use of macroporous membranes to provide an interface between a gas and a liquid absorbent and are being developed for CO2 removal from flue gases and for natural gas sweetening. The relatively large pore diameter of the membrane, typically in the range of 10
200 nm, means that the

Membrane separation systems

223

Table 8.13 Advantages of gas
liquid membrane contactors Advantage

Description

High area-to-volume ratio

Currently available hollow-fiber membrane modules offer packing densities up to 7000 m2/m3, compared to , 350 m2/m3 for traditional packed and plate column contactors, resulting in mass transfer rates 100
1000 times higher, as well as significant weight and space reductions Ability to independently control gas and liquid flow rates to optimize the absorption process, avoiding operational problems encountered in distillation processes such as liquid entrainment in the gas phase or column flooding

No interpenetration of gas and liquid phases

membrane itself is non-selective and the selectivity of the contactor results from the physical or chemical absorption process at the permeate side of the membrane. This hybrid membrane
absorbent configuration offers significant advantages compared to the traditional column-type adsorption contactors, as summarized in Table 8.13. An important characteristic of the membrane
absorbent combination is that the membrane should not be wetted by the solvent solution, so that the pore space remains fully gas-filled to maximize mass transfer through the membrane. The critical differential pressure at which pores will become wetted is determined by Laplace
Young equation: ΔPc 5 2 4γ cos θ=dmax

(8.22)

where ΔPc is the critical breakthrough (i.e., wetting) pressure, γ is the surface tension of the solvent, θ is the contact angle in degrees for the gas solvent membrane system, and dmax is the maximum diameter of the membrane pores. The need to avoid pore wetting and the precise pressure control across the membrane that is needed both to ensure this and to avoid liquid breakthrough are significant operational challenges balancing the advantages noted above. Other solvent requirements include the ability to achieve a high CO2 loading at the relatively low partial pressures achievable on the permeate side of the membrane, low viscosity to reduce energy requirements for solvent circulation through hollow-fiber modules, and low volatility to reduce solvent losses. The traditional amine-based solvents have been used in experimental work but require the use of more expensive membrane materials, such as PTFE (Teflon) or polyvinylidene fluoride, to avoid the problem of membrane wetting. Recent research has focused on the use of commercially available hollow-fiber membrane modules, using inexpensive membrane materials such as polypropylene, requiring either alternative non-wetting solvents (higher γ and θ) or treatment of the membrane material to make it less hydrophilic (increase θ), such as plasma treatment or the application of a thin hydrophobic coating.

224

Carbon Capture and Storage

A number of pilot-scale examples of membrane contactors for CO2 capture have been reported, including a demonstration unit using Teflon (PTFE) membranes and a conventional amine solvent developed by Aker Kvaerner. This unit was able to recover 85% of the CO2 from the exhaust gas of a 520 kW gas turbine engine, at a rate of 195 kg-CO2/h from 2610 kg/h of exhaust gas, with a solvent flow rate of 4.5 m3/h. Significant recent effort has also been devoted to the development of mathematical modeling techniques for membrane contactors, to enable optimization of solvent and contactor characteristics, operating conditions, and integration into overall capture process.

8.5

References and resources

8.5.1 References Baker, R., 2004. Membrane Technology and Applications. John Wiley & Sons, Chichester, UK. Bredesen, R., Jordal, K., Bolland, O., 2004. High-temperature membranes in power generation with CO2 capture. Chem. Eng. Process. 43, 1129
1158. Cejka, J., van Bekkum, H., Corma, A., Schueth, F., 2007. Introduction to Zeolite Molecular Sieves. Elsevier, Oxford, UK. Dai, Z., Noble, R.D., Gin, D.L., Zhang, X., Deng, L., 2016. Combination of ionic liquids with membrane technology: a new approach for CO2 separation. J. Membr. Sci. 497, 1
20. Favre, E., 2007. Carbon dioxide recovery from post-combustion processes: can gas permeation membranes compete with absorption? Membr. Sci. 294, 50
59. Kai, T., Duan, S., Ito, F., Mikami, S., Sato, Y., Nakao, S., 2017. Development of CO2 molecular gate membranes for IGCC process with CO2 capture. Energy Procedia. 114, 613
620. Khalilpour, R., Mumford, K., Zhai, H., Abbas, A., Stevens, G., Rubin, E.S., 2015. Membrane-based carbon capture from flue gas: a review. J. Clean. Prod. 103, 286
300. Koros, W.J., Y.H. Ma, T. Shimidzu, 1996. Terminology for Membranes and Membrane Processes. IUPAC Recommendations (see also Web resources). Loeb, S., 1981. The Loeb-Sourirajan membrane: how it came about. In: Turbak, A. (Ed.), Synthetic Membranes, ACS Symposium Series. American Chemical Society, Washington, DC. Available at , http://pubs.acs.org/doi/pdf/10.1021/bk-1981-0153. ch001 . . Mano, H., Kazama, S., Haraya, K., 2003. Development of CO2 separation membranes (1) polymer membrane. In: Gale, J., Kaya, Y. (Eds.), Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies. Elsevier, Oxford, UK. Peters, T.A., Rørvik, P.M., Sunde, T.O., Stange, M., Roness, F., Reinertsen, T.R., Ræder, J.H., Larring, Y., Bredesen, R., 2017. Palladium (Pd) membranes as key enabling technology for pre-combustion CO2 capture and hydrogen production. Energy Procedia. 114, 37
45. Rezakazemi, M., Amooghin, A.E., Montazer-Rahmati, M.M., Ismail, A.F., Matsuura, T., 2014. State-of-the-art membrane based CO2 separation using mixed matrix membranes (MMMs): an overview on current status and future directions. Prog. Polym. Sci. 39, 817
861. Sandru, M., Kim, T.-J., Capala, W., Huijber, M., Ha¨gg, M.-B., 2013. Pilot scale testing of polymeric membranes for CO2 capture from coal fired power plants. Energy Procedia. 37, 6473
6480.

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Ward, W.J., Robb, W.L., 1976. Carbon dioxide
oxygen separation: facilitated transport of carbon dioxide across a liquid film. Science. 156, 1481
1484. Warmuzinski, K., Tanczyk, M., Jaschik, M., 2015. Experimental study on the capture of CO2 from flue gas using adsorption combined with membrane separation. Int. J. Greenhouse Gas Control. 37, 182
190. White, L.S., Wei, X., Pande, S., Wu, T., Merkel, T.C., 2015. Extended flue gas trials with a membrane-based pilot plant at a one-ton-per-day carbon capture rate. J. Membr. Sci. 496, 48
57. Wilcox, J., Haghpanah, R., Rupp, E.C., He, J., Lee, K., 2014. Advancing adsorption and membrane-separation processes for the gigaton carbon capture challenge. Annu. Rev. Chem. Biomol. Eng. 5, 479
505. Zhang, Y., Sunarso, J., Liu, S., Wang, R., 2013. Current status and development of membranes for CO2/CH4 separation: a review. Int. J. Greenhouse Gas Control. 12, 84
107. Zhao, S., et al., 2016. Status and progress of membrane contactors in post-combustion carbon capture: a state-of-the-art review of new developments. J. Membr. Sci. 511, 180
206.

8.5.2 Resources Cameron (membrane systems development and manufacture for natural gas processing): www.c-a-m.com/products-and-services IUPAC Terminology for Membranes and Membrane Processes: pac.iupac.org/publications/ pac/pdf/1996/pdf/6807x1479.pdf Membrane Technology and Research Inc. (development and manufacture of membrane separation systems): www.mtrinc.com NanoGLOWA project (development of facilitated transport membranes for post-combustion capture): http://cordis.europa.eu/project/rcn/81551_en.html Norwegian University of Science and Technology (NTNU; membrane technology research): www.chemeng.ntnu.no/memfo PoroGen Corporation (innovative membrane manufacturer): www.porogen.com/technology. html Research Triangle Institute (R&D on membrane separation systems): www.rti.org/page.cfm/ Membrane_Development TNO (membrane contactor development): www.tno.nl/en/focus-area/industry/sustainablechemical-industry/efficient-processing/membrane-contactors Universal Oil Products (UOP) (membrane systems development and manufacture): www. uop.com/tech-library

Low temperature and distillation systems

9

Distillation has been applied as a technique for separating a mixture of liquids since the second millennium BC, when it was used in Mesopotamia for the preparation of perfumes, and has been used for alcohol preparation since at least 500 BC. Modern industrial distillation methods were first developed in the 1800s, driven by the need for large-scale alcohol and industrial chemical production, and these techniques have been an area of considerable development since then due to their importance in the petrochemical industry. The origins of refrigeration can also be traced back to Mesopotamia in the same millennium, with the first ice houses built around 1780 BC, but it was not until 1805 that the first vapor-compression refrigeration cycle was designed by American inventor Oliver Evans, and another 100 years before Carl von Linde liquefied air, heralding the arrival of cryogenics. Distillation and low-temperature (including cryogenic) techniques are relevant to CCS in several areas: post-combustion separation of CO2 can be achieved by cryogenic freezing (desublimation), by hydrate formation or using hybrid membrane
cryogenic systems, CO2 can be separated from syngas by hydrate formation, and oxygen can be produced by cryogenic air separation for oxyfuel combustion. In addition, CO2 can be separated from natural gas either to treat gas to sales specification or to separate CO2 produced in an EOR project for reinjection.

9.1

Distillation systems

9.1.1 Physical fundamentals The separation of a mixture of liquids by distillation into its components depends upon the difference in the boiling points and volatilities of the components. Every liquid (and to a lesser extent every solid) has a tendency to evaporate as a result of the escape of molecules from the liquid surface, and the greater that tendency is the more volatile the substance is said to be. When a liquid is in equilibrium with its vapor, the pressure of the vapor is called the equilibrium vapor pressure. The vapor
liquid distribution ratio (or K-value) is used to characterize the volatility of a substance and is defined as: K 5 CV =CL

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00009-X © 2017 Elsevier Inc. All rights reserved.

(9.1)

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where CV is the concentration of the substance in the vapor phase and CL is the concentration in the liquid phase, at a given temperature and pressure. A substance with a higher vapor pressure will have a higher concentration in its vapor phase at any given temperature and pressure and will therefore have a higher K-value. In a binary mixture, the relative volatility (αij) of the two components (i and j) at a given temperature and pressure is given by: αij 5 Ki =Kj

(9.2)

and is therefore governed by the ratio of their vapor pressures. Mixtures with higher relative volatilities are easier to separate by distillation. As temperature increases, the vapor pressure of a liquid increases until the point is reached at which the vapor pressure becomes equal to the surrounding pressure; this is the boiling point of the liquid. While every pure chemical has a single boiling point, a mixture, such as the binary mixture of water and ethanol, boils over a range of temperatures depending on the ratio of components in the mixture. This is illustrated in Figure 9.1, which shows a schematic boiling point diagram of a binary mixture at a given pressure. The boiling point of the mixture lies between the boiling points Ti of the pure component i and Tj of component j. Considering a mixture with 25% mole fraction of component i, the boiling point of this mixture is represented by point B, the bubble point curve being the curve joining the boiling points for all mixing ratios. In the superheated vapor region, no liquid phase is present. As a vapor mixture in this region is cooled (line DC), a liquid phase will start to condense when the temperature drops to the dew point (point C). The dew point curve joins all such points across the mixing ratio. Considering again the mixture with 25% mole fraction of component i (point A); when this mixture is heated to its boiling point (point B), the vapor produced has an 120 Superheated vapor

Temperature (⬚C)

110 100

D C

B

Dew point curve

90 A 80 70 0.0

Bubble point curve

Subcooled liquid

0.2 0.4 0.6 0.8 Concentration of component i (mole fraction)

Figure 9.1 Boiling point diagram of a binary mixture.

1.0

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229

equilibrium composition given by point C, on the dew point curve at this temperature. This mixture has a higher mole fraction of component i, B70% in Figure 9.1, as a result of the higher relative volatility of this component. The remaining liquid has a reducing mole fraction of this component and, if the original liquid mixture is not replenished, the boiling point of the remaining mixture will rise and boiling will cease. This illustrates the process of separation by distillation, with a vapor stream that is rich in the lower boiling point component and a residual liquid stream that is lean in that component and rich in the other.

9.1.2 Distillation column configuration and operation Industrial-scale distillation employs large distillation columns, in which multiple separations of this kind occur. Figure 9.2 illustrates part of the internal structure of a distillation column (two trays). The column is heated at its base by an internal heater or heat exchanger, or by liquid recycled from an external reboiler, to a temperature close to the boiling point of the required bottom stream. Similarly it is cooled at the top by an internal condenser or cooled reflux stream, to a temperature that is just above the boiling point of the required top-stream product. In separating a binary mixture, these would be the boiling point temperatures of the two pure components. The input liquid stream is fed into the column and covers the “feed tray.” The temperature at this point in the column is at the boiling point of the feed mixture so that vapor that is rich in the volatile component rises up toward the tray above the feed, while residual liquid that is rich in the less-volatile component pours over the weir and drops to the next lower tray. Rising vapor passes either through holes in a sieve type tray, through lifting valves or, in the example shown, below bubble caps, and bubbles into the liquid in the tray above. This liquid is the condensed phase that is falling from higher,

Bubble caps

Weir

Vapor

Figure 9.2 Tray structure within a distillation column.

Liquid

Feed

Liquid

Trays

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and therefore cooler, trays in the tower. The same separation process occurs here, yielding a vapor that is progressively richer in the volatile component at successively higher trays. This section of the column, above the feed inlet, is called the rectification section. A similar process occurs in the trays below the feed with the liquid in successively lower, and therefore hotter, trays being progressively richer in the less volatile component. This section of the column is called the stripping section. The number of trays needed to achieve a specific separation requirement depends on the relative volatility of the components to be separated. For a binary mixture, if αij is close to 1, the bubble point and dew point lines in Figure 9.1 will be close together, and relatively little change in composition of the mixture will be achieved in each separation stage. In this situation a larger number of trays would be required to achieve a specified purity of the two streams compared to the situation in which the bubble point and dew point lines are far apart. As well as the vapor
liquid equilibrium behavior, the key operating parameters that determine the number of trays are the reflux rate and the condition of the feed (e.g., feed temperature and phase state (liquid, mixed, or vapor)), and various analytical methods are available to calculate the required number of trays for a particular separation task (e.g., McCabe
Thiele diagram or Fenske equation). A packed column is an alternative to the tray column described above in which the trays are replaced by a continuous packing material, typically a structured sheet metal in the form of corrugated metal plates (Figure 9.3). This configuration increases the contact area between vapor and liquid, since liquid will condense on and wet the whole surface area of the packing material, and allows a reduction in the physical size of the column for a given separation requirement. In this case, design of the column involves determining both the number of trays required and

Figure 9.3 Distillation column trays (left) and structured packing material (right). Source: New Tianjin Corp. (trays) and Sulzer Chemtech (structured packing).

Low temperature and distillation systems

231

Condenser

Feed

Distillation column

Reflux

Cooling water

Trays or packing

Offgas Pump

Reflux drum

Overhead product Vapor Heating steam Reboiler Bottom liquid

Bottom product

Figure 9.4 Distillation column process flow scheme.

the so-called height (of packing material) equivalent to a theoretical plate. The required height of a packed column is then the product of these two numbers. Figure 9.4 shows a simplified process scheme for a distillation column. As well as cooling the top of the column, the reflux stream also serves to increase the concentration of the volatile component in the upper part of the column, reducing the boiling point of the mixture and therefore keeping the less-volatile component in the liquid phase. This increases the efficiency of the separation process and reduces the number of trays required to achieve the required degree of separation. Practical distillation process design also needs to take into account the range of operating conditions over which column performance must be sustained, for example, considering possible variations in feed composition, feed rate, and ambient temperature. Problems that can reduce separation efficiency include: G

G

G

Entrainment: upward transport of excessive liquid as a result of high vapor rates Weeping: excessive downward liquid rates due to low vapor pressure Foaming: liquid expansion due to the retention of vapor bubbles in the liquid, commonly due to the presence of surfactant components in the feed stream

9.2

Hydrate-based capture

9.2.1 Physical fundamentals Gas hydrates, also known as clathrate hydrates or clathrates, are a crystalline phase of water in which a guest molecule is trapped within a cage of hydrogen-bonded

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SI cages 512 Guest

SII cages 512

Water cage

51262

51264

SH cages 435663

51268

Figure 9.5 CO2 hydrate cage structures. Source: Graphic elements from Yang (2011) and Ma (2016).

water molecules and were discovered by Humphry Davy in 1811. In the case of CO2 hydrates, the cage of water molecules takes the form of a 12- or 14-faced polyhedra (dodecahedron or tetradecahedron) having pentagonal or hexagonal faces with an oxygen atom at each vertex, similar to normal ice, as illustrated in Figure 9.5. These polyhedra are denoted by the nomenclature 512 and 51262, respectively, where AmBn indicates a polyhedron with m A-sided and n B-sided faces. CO2 and methane hydrates have an overall crystalline structure designated Type I (or SI), in which the unit cell consists of 46 water molecules forming two small (512) and six larger (51262) cages. All such cages need not be occupied, and a key challenge in hydrate-based gas separation is to maximize occupancy by the desired guest molecule. If all cages are occupied, the stoichiometry of this structure, for CO2, is (CO2:5.75H2O). Larger guests, such as O2, N2 and many thermodynamic promoters (see below) form Type II (SII) hydrate structures, with a unit cell of 136 water molecules forming sixteen small (512) and eight larger hexadecahedral (51264) cages; hydrogen also forms SII hydrates, but in this case the cages are occupied by clusters of two or four H2 molecules. Even larger guests, such as butane (C4H10), form Type H (SH) structures with two types of small cage (three 3 512 and two 3 435663) and one very large 51268 cage. The largest guests, often used as chemical hydrate promoters (see below), form semi-clathrates in which the largest cages are broken—to accommodate the oversize guest—and other, smaller guests form part of the cage structure as well as occupying the smaller cages. The formation of hydrates occurs under conditions of low temperature and high pressure; the equilibrium phase diagram of some CCS relevant gases is shown in Figure 9.6 (the hydrate formation region is above the line in each case). This

Low temperature and distillation systems

233

50

250 N2 O2

Pressure (MPa)

40

30

200 H2

150 0.18 CO2 + 0.82 N2

20

10

100

50 CH4 CO2

0

0 0

5

10

–5

0

Temperature (°C)

Figure 9.6 Equilibrium phase diagram for the hydrates of some CCS relevant gases.

process, also known as enclathration, is exothermic, the enthalpy of formation for CO2 hydrate being B65 kJ/mol-CO2. When hydrate formation is used for the separation of gas mixtures, the keep requirements are as follows: G

G

G

Short induction time: the time taken for hydrate crystal nuclei to form in the gas
water mixture High gas consumption: the total amount of gas taken up as clathrate in the process, a convenient measure being the hydration number Hydration number ðSI Þ 5 46=ð6θL 1 2θS Þ

(9.3)

Hydration numberðSII Þ 5 136=ð8θL 1 16θS Þ

(9.4)

where θL and θS measure the occupancy of large and small cages. For maximum occupancy (θL 5 θS 5 1) the hydration numbers for SI and SII hydrates are 5.75 and 5.66, corresponding to maximum theoretical gas uptake of 0.174 and 0.176 mol-gas/mol-water. In SI hydrates, all cages can be occupied by CO2 giving a maximum theoretical uptake of 0.174 mol-CO2/mol-water; SII hydrates however can only enclathrate CO2 when stabilized by a larger promoter molecule, which will occupy the large cages, leading to a maximum theoretical uptake of 0.118 mol-CO2/mol-water. High CO2 recovery from the feed gas stream; this is measured by the split fraction, denoted S.Fr feed S:Fr 5 nH co2 =nco2

(9.5)

being the ratio of the number of moles of CO2 in the hydrate (H) versus feed. Values of S.Fr of 0.35
0.40 are typically reported for single-stage CO2 separation (B10 MPa, B0.5 C) from simulated flue gas mixtures with 15%
20% CO2 content.

234

G

Carbon Capture and Storage

High separation efficiency of CO2 versus other gases enclathrated from the feed stream, denoted by the separation factor S.F gas gas H S:F 5 ðnH CO2 3 nA Þ=ðnCO2 3 nA Þ

(9.6)

where “A” denotes another gas component in the feed and ngas indicates moles in the residual gas phase. Values of S.F of 10
15 are typically reported for single-stage CO2 separation from simulated flue gas with a 15%
20% CO2 content, where the “A” component is nitrogen.

As one might anticipate, these are competing requirements; for example, raising the operating pressure will reduce the induction time and increase overall gas consumption but will generally reduce the separation factor, as other gases will also be enclathrated. It also increases the energy requirement for compression, which would result in undesirable additional operating cost. Chemical additives, known as hydrate promoters, have been a major recent R&D focus with the aim of improving all the above factors. Thermodynamic promoters, of which tetrahydrofuran (THF, C4H8O) is a much studied example, are chemicals which form clathrates at very low pressure. In the case of THF, which is a relatively large molecule, type SII clathrates form rapidly at 1 bar and 4.5 C. Both the large 51264 and small 512 cavities can be occupied by CO2, but there is competition for occupancy with other molecules, including THF itself, and H2 or N2, depending on the CO2 separation application (pre- or post-combustion). The impact of a number of thermodynamic promoters, including propane, THF, and tetra-n-butyl ammonium bromide, on the equilibrium hydration conditions for IGCC fuel gas is shown in Figure 9.7. Although these promoters are effective at accelerating hydrate formation and moving the equilibrium hydrate formation line to lower pressure/higher 12 Fuel gas (40% CO2, 60% H2)

Pressure (MPa)

10

+ C3H8 2.5mol%

+ THF 5.6mol%

+ TBAF 3.3mol%

8 6 CO2 4 2 0 0

10

20

30

Temperature (°C)

Figure 9.7 Impact of thermodynamic promoters on equilibrium hydration of IGCC fuel gas. Source: After Babu, 2015.

Low temperature and distillation systems

235

temperature, they tend to adversely effect gas consumption and split fraction, since many of the clathrate cages will be occupied by promoter molecules. Surfactants are another type of chemical additive which work as kinetic promoters, enhancing the solubility of the target gas in water and accelerating the formation of gas hydrate but, unlike thermodynamic promoters, not directly affecting the clathrate formation process. Surfactant molecules contain both hydrophobic and hydrophilic sites; association of gas 1 surfactant molecules occurs at the hydrophobic site and inclusion of the gas molecule into the growing hydrate cages is then facilitated by the strong affinity to water at the surfactant’s hydrophilic site.

9.2.2 Configuration and operation of hydrate separation systems One possible configuration of a single-stage CO2 hydrate separation unit is shown schematically in Figure 9.8. The feed gas mixture and water are mixed at the required operating temperature and pressure in a hydrate formation reactor, commonly a stirred tank in current bench-scale development systems. After a residence time for hydrate formation, the residual gas, now lean in CO2, is separated from the CO2-rich hydrate slurry in a separator, and the hydrate slurry is then dissociated by a combination of heating and pressure reduction in a dissociation reactor. The system shown could be considered the current “base case” configuration. The development of hydrate-based separation systems is still in its infancy and work to date has largely been using bench-scale systems with reactor capacities of a few hundred cm3. The first pilot-scale work was reported in 2013 and used a

CO2 lean gas

CO2 rich gas

Feed gas

Hydration formation reactor

Gas plus hydrate slurry

Separator

Water

Figure 9.8 Hydrate-based separation process schematic.

Hydrate slurry

Dissociation reactor

236

Carbon Capture and Storage

simplified version of the process described above. Agitation of the 5.6 L hydration reactor was achieved using a jet pump instead of stirring; separation took place by the simple overflow of hydrate from the formation reactor to the dissociation reactor, eliminating the need for a separator, and two parallel dissociation reactors were employed. The latter configuration was used to achieve two-stage hydrate separation with a single formation reactor, the off-gas from the first dissociation reactor being used as feed gas for a second stage of separation. Alternatively such a configuration could enable continuous operation of a single separation stage. The installation is shown in Figure 9.9. A wide variety of alternative approaches have been proposed or demonstrated at laboratory scale to improve hydrate formation performance in a continuous (nonbatch) process, including fixed bed reactors containing silica sand, silica-gel or glass beads, aluminum, polyurethane or cellulose foam or metal packing, tubular flow reactors, and bubbling columns fed with 50 µm gas bubbles. The fixed bed reactor seems a promising option and achieves an improved rate of hydrate formation, as well as high water to hydrate conversion, gas consumption, and CO2 recovery as a result of the high surface area of gas to liquid contact in the porous medium when compared to a stirred tank reactor. After a hydrate formation period, dissociation would take place directly from the fixed bed after purging to remove excess water and residual gas. Continuous gas separation would then be achieved using a number of beds in parallel, analogous to the Skarstrom PSA cycle discussed in Chapter 7.

Figure 9.9 Pilot-scale hydrate separation unit. Source: Xu et al. (2013)

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237

While hydrate-based separation of CO2 from mixed gas streams has as advantage over other methods in its moderate operating temperature (0
10 C) and ease of recycling the environmentally friendly water “solvent,” the key disadvantage in the case of post-combustion capture is the large energy penalty due to the need to compress flue gas from 0.1 to around 10 MPa. For a 1 GW power station this penalty has been estimated at 158 MW (including heat and compression power recovery, but excluding any benefit from chemical additives) clearly demonstrating the need for further process improvement. As syngas is typically produced at 2.5
5 MPa in an IGCC power plant and the CO2:H2 hydrate separation takes place at about 8 MPa, this penalty is significantly smaller in the case of pre-combustion capture, as both the gas volume and compression step are reduced.

9.2.3 Integrated and hybrid hydrate separation systems Hybrid hydrate/membrane systems As noted above, a single-stage hydrate separation process operating on flue gas would typically give a 10
15 separation factor and a 0.35
0.40 split fraction, yielding a final CO2 rich stream containing 55%
60% CO2. To achieve higher recovery and a purer CO2 stream, the process can be cascaded to include two- or three-stage hydrate separation with additional CO2 recovery from the residual gas using a membrane separation unit. Multistage hybrid processes for pre- and post-combustion CO2 capture are shown schematically in Figures 9.10 and 9.11. The pre-combustion process shown here is

CO2 lean

10% CO2 Membrane process

Feed gas 17% CO2 Water

50% CO2

Gas hydration process

57% CO2 Water

Gas hydration process

N2 CO2

70% CO2

83% CO2 Water

Gas hydration process

Figure 9.10 Hydrate/membrane post-combustion gas separation process. Source: After Linga et al. (2007).

98–99% CO2

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Carbon Capture and Storage

20% CO2 Syngas 40% CO2 Water

H2

Membrane process

CO2

70% CO2

Gas hydration process

CO2 recycle

85% CO2

Gas hydration process

Water

98%–99% CO2

Figure 9.11 Hydrate/membrane pre-combustion gas separation process. Source: After Linga et al. (2007).

Enriched H2

Cold H2

Cold feed

Cryogenic H2/CO2 Separator

Hydrate reactor

–55°C

–1°C

CO2 liquid Syngas feed

Heat exchanger

Hydrate slurry

Heat exchanger

Dryer

CO2 gas Dissociation reactor Water recycle

CO2 96mol% at ~10MPa

CO2 90mol% at ~2MPa

Hydrogen to customer

Figure 9.12 Hybrid cryogenic/hydrate CO2 separation process.

able to achieve the required output specification in two stages due to the higher CO2 concentration in syngas versus flue gas. One aim of current R&D work is to use at most two hydrate stages to also achieve the required separation in the post-combustion case.

Hybrid cryogenic/hydrate systems A combined cryogenic/hydrate system has also been demonstrated for CO2 separation from syngas. In this system, shown in Figure 9.12, the first stage is liquefaction of CO2 in a cryogenic separator operating at the syngas supply pressure (5
6 MPa) and a temperature of B55 C, which removes some 70
75 mol% of

Low temperature and distillation systems

239

the CO2 in the feed stream and delivers this as a 96% pure high pressure CO2 stream. The enriched hydrogen off-gas from the cryogenic stage is fed to a hydrate reactor at 1 C where a further 10
20 mol% of CO2 is removed as hydrate. The off-gas from the hydrate reactor, containing B7 mol% CO2, is reheated and fed to the power plant, while dissociation of the hydrate slurry yields a further 90 mol% pure CO2 stream at B2
4 MPa.

9.3

CO2 capture by cryogenic separation

9.3.1 Physical fundamentals Low-temperature phase behavior of CO2 Depending on the operating pressure, cooling of a gas mixture containing CO2 will result in the condensation of a liquid CO2 stream at pressures between the critical and triple points or the desublimation (anti-sublimation or frosting) of solid CO2 at pressures below the triple point, as illustrated in Figure 9.13. As a result, pre-combustion cryogenic separation of CO2 from syngas, at gasification operating pressures of a few MPa, is liquefaction of the gas, while postcombustion separation from flue gas at close to atmospheric pressure is desublimation. The desublimation or frosting temperature of a component within a mixture of gases depends on its concentration or partial pressure within the mixture, as show in Figure 9.14 for CO2 in flue gas mixture. As a result, cryogenic separation by desublimation needs to take place well below the frosting temperature of the pure gas, in order to achieve a low residual concentration in the process off-gas. The normal boiling point at 1 bar (NBP) of 1000

Pressure (MPa)

100

Solid

Supercritical fluid Liquid

10 Liquefaction

Critical point (7.38MPa, 31.1°C)

1 Triple point (518kPa, –56.6°C)

Gas

Desublimation

0.1 –100

0 Temperature (°C)

Figure 9.13 Phase diagram of CO2.

100

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Carbon Capture and Storage

Figure 9.14 Frosting temperature of CO2 in a flue gas mixture at 100 kPa. Table 9.1 NBPs of air and flue gas components Flue gas component

PCC flue gas composition

NBP at 1 bar ( C)

N2 O2 H2O Ar

76% 6% 6% 1%

2196 2183 100 2186

1.0

CO2 separation ratio (%)

Separation at 3MPa

0.8

0.6

70% CO2 30% H2 40% CO2 60% H2

0.4

0.2 –81°C

–57°C

0.0 –100

–80

–60

–40

–20

0

Temperature (°C)

Figure 9.15 CO2 recovery from CO2/H2 mixtures as a function of [CO2] and temperature.

other flue gas and air components are listed in Table 9.1. Apart from water vapor, other components will remain in a gaseous state at the temperatures required for desublimation. Analogous to the [CO2] dependence of frosting temperature, CO2 recovery from a gas mixture by liquefaction is also a function of [CO2] as shown in Figure 9.15.

Low temperature and distillation systems

241

Critical point QH

WC HC

HB HC Expander

Vapor

Compressor

HA

Evaporator

Condensation C

D Pressure

Condenser

QH

WC

Expansion

Compression Liquid

QL

A

Evaporation

B QL

Liquid + Vapor Volume

Figure 9.16 Vapor-compression refrigeration cycle.

Reverse Carnot cycles Practical Carnot cycles, such as the Rankine steam cycle and Brayton gas cycle, were discussed in Chapter 3, as the basis of generating mechanical work through the thermodynamic manipulation of a working fluid. In a reverse Carnot cycle, mechanical work is applied to alter the thermodynamic state of the working fluid, so that the fluid can be used to extract heat from an external medium—i.e., to cool or refrigerate that medium. Vapor compression is the most common refrigeration process and is widely used for applications such as air conditioning and domestic or industrial refrigeration. The process, essentially a Rankine cycle in reverse, uses a working fluid with a boiling point below the required cold temperature, as illustrated in Figure 9.16 (c.f. Figure 3.3): G

G

G

G

From A to B: isobaric expansion and evaporation of the liquid component of the working fluid results in the uptake of heat (QL) from the refrigerated medium From B to C: adiabatic compression raises the temperature of the working fluid from TC to produce a superheated vapor at TH From C to D: isobaric condensation of the working fluid results in the rejection of heat (QH) to the cooling medium, typically ambient air or cold water From D to A: adiabatic flash of the working fluid through an expansion or throttle valve reduces the temperature to TC, the pressure reduction also leads to the partial evaporation of the working fluid to a liquid 1 vapor state.

One reverse Carnot cycle in which the working fluid does not undergo a phase change, similar in this respect to the Brayton cycle, is the Stirling cooling cycle. The components and operation of the Stirling cooler are illustrated in Figure 9.17. The cooler consists of two pistons: one at TH (the “hot end”) and one at TL (the “cold end”); two heat exchangers operate between the working fluid and the ambient medium at the hot end and the refrigerated medium at the cold end; and a regenerator which retains and releases heat as the working fluid, typically helium gas, moves within the cooler.

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Carbon Capture and Storage

Cold heat exchanger

Warm heat exchanger Warm piston

Compression space

TH

TL A

Cold piston

Expansion space

Regenerator

B

C

Pressure

QR B

Isochoric cooling C

Isothermal compression

QH

Isothermal expansion D

A Isochoric heating

QL

QR D

Volume

Figure 9.17 Stirling cooler configuration and refrigeration cycle.

At point A, all of the gas is in the hot compression space and the regenerator: G

G

G

G

From A to B: the hot piston moves to the right, compressing the gas isothermally; the constant temperature is maintained by removing heat (QH) from the gas in the heat exchanger From B to C: both pistons move to the right, resulting in isochoric (constant volume) cooling of the gas, as heat (QR) is taken up by the regenerator From C to D: the cold piston continues to move to the right, expanding the gas isothermally; the heat (QL) required to maintain constant temperature is taken up from the refrigerated medium via the cold heat exchanger From D to A: both pistons move to the left, resulting in isochoric heating of the gas as it takes up the heat (QR) previously stored in the regenerator

In a commonly used variant of this basic Stirling cooler, the pistons are replaced by magnetically actuated diaphragms, similar to loudspeakers, thereby eliminating the need for moving gas seals and achieving very high lifetimes. Many different configurations of Stirling and other cooler types have been developed and used in a wide variety of applications from instrument cooling in satellites and night vision systems to air liquefaction. Applications range from a few mW for electronic device cooling to less than 5K to megawatt systems for air and natural gas liquefaction at around
120 C.

9.3.2 Pre-combustion cryogenic separation As a result of the maturity of cryogenic systems for gas processing, the demonstration and early deployment of cryogenic carbon capture systems has been more rapid

Low temperature and distillation systems

243

than for many other CCS technologies. A good example of this rapid development is the Cryocapt system developed by Air Liquide (Pichot et al., 2017). This cryogenic capture system has been deployed at a 100 kt-CO2/year scale to separate CO2 from H2 at Air Liquide’s hydrogen production unit located in Port-Je´rˆome, Normandy, France, which produces hydrogen for a nearby refinery. After steam methane reforming, the hydrogen product is recovered by pressure swing adsorption (PSA) and CO2 is separated from the PSA retentate stream by condensation and distillation in a cold box operating close to the triple point. This technology is also being developed for application in the steel industry. A hybrid PSA/cryogenic system has also been proposed for CO2 separation from syngas (Xu, 2010). Recognizing that the cryogenic energy penalty for CO2 liquefaction is minimized at higher [CO2], the syngas is first treated in a PSA stage to yield a high purity (.99.9%) H2 stream for combustion. A CO2 stream is used to purge the PSA during the desorption step, yielding an input stream for liquefaction with about 80 mol% CO2 and 20 mol% H2. Two-stage liquefaction at
36 C (first stage at 2 MPa, second at 5 MPa) recovers 90% of the CO2 into 99% pure liquid stream, while the residual off-gas (30 mol% CO2, 70 mol % H2) can be either recycled to the PSA input or consumed as a gas turbine fuel for internal process power. The overall energy penalty of this process, further minimized by effective heat and cold energy recovery, can be as low as 0.4 MJ/kg-CO2. Alternative syngas treatment configurations have also been proposed in which the retentate from a WGS membrane reactor (see Section 8.4.2) is first combusted in an oxyfueled combuster, providing process heat and power. This removes all combustibles (H2, CH4, CO) yielding a predominantly CO2 flue gas stream which is dried and further purified either by cryogenic liquefaction or low-temperature distillation.

9.3.3 Post-combustion cryogenic separation The capture of CO2 by cryogenic desublimation from post-combustion flue gas at or close to atmospheric pressure was first proposed and demonstrated in 2002. The system first chilled flue gas to
40 C to remove water down to a sufficiently low level (0.08 g-H2O/kg-dry flue gas) to prevent ice fouling later in the process. The dry flue gas was then chilled to 2120 C, causing CO2 frost to form in the cooling vessel heat exchanger. Gas feed was then switched to a second cooling system to enable CO2 recovery by heating of the first. The cooling system used four-stage vapor compression refrigeration with a blended refrigerant composed of n-butane (NBP 5 20.5 C), propane (NBP 5 242.2 C), ethane (NBP 5 288.6 C), and methane (NBP 5 2161.4 C). Depending on the overall efficiency of the cooling system, including heat/ cold recovery, it was estimated that the energy penalty for the system could be as little as 0.54
1.1 MJ/kg-CO2, one-third or less of that required for amine-based capture (see Section 6.3). A three-step cycle (cooling, capture, and recovery) was later demonstrated using three parallel packed beds, with CO2 desublimation occurring as a cold front moves through the bed, analogous to the mass transfer zone in

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an adsorption bed, discussed in Section 7.1. In the recovery step, warm CO2 is used to drive a warm front through the bed. Since the [CO2] in this stream is higher than in the feed to the cooling step, some of this CO2 will initially desublimate in the bed but will be recovered as the bed warms further. The energy requirement for this system to achieve 99% CO2 recovery from dry simulated flue gas was 1.8 MJ/kgCO2 and one option that has been proposed to reduce the cost of this energy is to integrate cryogenic capture with LNG regasification, in order to exploit the cold energy from this process. CO2 liquefaction has also been proposed as a post-combustion capture technique, although this requires front-end compression to deliver feed gas above the triple point pressure. As noted in the previous section, the energy efficiency of CO2 liquefaction from a gas mixture increases as [CO2] in the mixture increases. In a system developed by Air Liquide (Figure 9.18) this is achieved by first passing the compressed and chilled flue gas through commercially available hollow fiber membranes, chilled to
30 C. Cooling these membranes to below
20 C was found to increase CO2/N2 selectivity by a factor of 2
4 with minimal loss of permeance. Cryogenic separation of liquid CO2 then takes place at
57 C to yield the product stream, while off-gas from the separation is recycled to the membrane feed after cold energy recovery. CO2 liquefaction can also been applied to the purification of the CO2 stream from oxy-combustion flue gases, as demonstrated at the Cuiden oxyfuel pilot (see Delgano et al., 2014).

CO2 product (6MPa, 20°C)

Heater CO2 depleted vent Turboexpander

Pre-treated flue gas

1.6MPa

Dryer

Water Feed compressor

Turboexpander

Cryo turboexpander

Heat exchanger

–30°C 1.5MPa

–57°C

Membrane

0.1MPa Permeate compressor

Cryogenic separator Liquid CO2 pump

Figure 9.18 Air Liquide hybrid cold membrane 1 cryogenic separation system. Source: After Haase et al. (2014).

Low temperature and distillation systems

9.4

245

Cryogenic systems for oxyfuel combustion

9.4.1 Cryogenic oxygen production The separation of oxygen from air for oxyfuel combustion can be achieved by a number of techniques, of which cryogenic systems are the most widely used for large-scale applications (more than B200 t-O2/day). Cryogenic air separation has been used for oxygen production since 1902, when the first air separation plant was constructed by Carl von Linde. This plant, with a capacity of 120 kg-O2/day, used Joule Thomson cooling together with countercurrent heat exchanger to liquefy air and then separate oxygen and nitrogen in a distillation column. The process is illustrated in Figure 9.19. Filtered air is compressed, accompanied by heating, and cooled back to ambient temperature in a heat exchanger, with water as the cooling fluid. The cooled highpressure air is fed through a countercurrent heat exchanger in which the returning end product from the cryogenic process is the heat sink. After this second cooling, the air is expanded through a valve and cooled to liquefaction temperature by Joule Thomson cooling. The liquefied air is then fed into a tray or packed distillation column. Since nitrogen has the lower boiling point, the vapor above each tray will tend to be nitrogen-rich while the liquid will be oxygen-rich, the liquid cascading down the stack of trays while the vapor rises. This simple single-tower process yields a pure liquid oxygen bottom stream and a gaseous nitrogen top stream typically containing 5%
10% of oxygen. An early enhancement was the addition of a second column (the Linde double column) to increase the purity of the nitrogen top stream. In an industrial ASU, water vapor and CO2 are removed after the first compression using molecular sieve units or absorption beds. A lower operating temperature for this air feed purification stage, achieved by additional cooling, improves CO2 and water vapor removal and Gaseous oxygen Air

Filtration Gaseous nitrogen Liquid nitrogen Liquid

Compression

nitrogen Heat exchanger Cooling water

Liquid oxygen cold box Dehydration

Water

Figure 9.19 Cryogenic air separation process.

Partially condensed air

Cryogenic distillation column

Refrigeration

Liquid oxygen

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Carbon Capture and Storage

Gaseous oxygen and nitrogen

Liquid oxygen and nitrogen

Air Filtration

Heat exchangers Compression

Argon distillation

Cooling N2 CO2

Dehydration CO2 removal

Compression and purification

Liquid argon

Double column Refrigeration

Distillation

Figure 9.20 ASU flow scheme. Table 9.2 Composition of air and NBPs of its components Component

Boiling point ( C)

Volume %

Helium Neon Nitrogen Argon Oxygen Krypton Xenon Carbon dioxide

2268.9 2246.1 2195.8 2185.9 2183.0 2153.2 2108.0 278.5

5.0 3 1024 1.8 3 1023 78.1 0.93 20.9 1.1 3 1024 9.0 3 1026 3.8 3 1022

makes overall plant performance less sensitive to seasonal changes in ambient temperature. Figure 9.20 shows a schematic flow scheme for a modern ASU. As can be seen from Table 9.2, the operating temperature of the distillation tower will be in the range 2196 C to 2183 C, between the boiling points of nitrogen and oxygen. Helium and neon will not be liquefied in the process and will stay in the vapor phase with nitrogen, while krypton and xenon, with higher boiling points, will remain in the liquid phase as impurities in the oxygen stream. Argon has a boiling point very similar to that of oxygen, and if a high-purity oxygen product is required (.95% pure) argon is removed at an intermediate point in the distillation column—the so-called argon belly—and can be separated and purified in additional distillation columns to yield a pure-argon product. The principles of cryogenic air separation remain unchanged since Linde’s 120 kg-O2/day prototype, but ASUs are now routinely constructed with single train capacities of up to 7000 t-O2/day. The world’s largest plant, at 30,000 t-O2/day, has been constructed by Linde AG for the Pearl Gas-to-Liquids project in Qatar using

Low temperature and distillation systems

247

Figure 9.21 ASU at the Schwarze Pumpe oxyfuel pilot plant. Source: Linde Group.

eight parallel 3750 t-O2/day trains. Figure 9.21 shows the ASU installed by Linde AG providing B240 t-O2/day to the Schwarze Pumpe oxyfuel pilot plant.

9.5

Ryan
Holmes process for CO2
CH4 separation

CO2 injection is a widely used technology for EOR, a process that will be described in Chapter 18. When CO2 breaks through into the oil-producing wells, it becomes necessary to separate CO2 from the gaseous hydrocarbon stream in order to produce sales-quality natural gas and LPG, the CO2 generally being returned to the field for reinjection. The separation of CO2 from light hydrocarbons by distillation is complicated by several factors: 1. At temperatures above
60 C, the vapor pressure of CO2 lies between those of methane and ethane and very close to that of ethane (Figure 9.22) 2. The risk of solid CO2 formation in the distillation tower if operated at temperatures and pressures to yield CO2 in the bottom stream and methane at the top 3. The formation of an azeotrope (see Glossary) between CO2 and ethane, preventing further CO2
ethane separation by simple distillation

The Ryan
Holmes process overcomes these problems in a low-temperature distillation process to separate CO2 from light hydrocarbons by the introduction of

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Carbon Capture and Storage

Vapor pressure (kPa)

4000

3000 CH4 Methane

C2H6 Ethane

CO2

2000

1000

0 –200

–150

–100

–50

0

50

Temperature (°C)

Figure 9.22 Vapor pressure versus temperature for CH4, C2H6, and CO2.

Glycol dehydration

Additive recovery

Methane removal

Molecular sieve dehydration

CO2 recovery

Compression

Residue gas Propane recovery

Inlet gas

NGL compression NGL sales

CO2 reinjection CO2 vaporization

Figure 9.23 Ryan
Holmes separation process.

additives into two stages of the distillation process, in the form of a chilled C51 hydrocarbon stream. The process flow is shown in Figure 9.23. The feed gas is first dehydrated, initially by contacting with ethylene glycol in a low-pressure dehydration tower, and finished at higher pressure by molecular sieve adsorption after compression. The dehydrated feed gas enters a propane recovery column, where propane and heavier hydrocarbon components (C31) are recovered in the bottom stream. The additive acts as an absorbent for propane and increases the separation efficiency of this first stage. This bottom stream is distilled in the additive recovery column, yielding an LPG (propane plus butane) top stream and recovering the C51 additive as the bottom stream. The top stream from the first stage is compressed and distilled in a CO2 recovery column, where CO2 plus ethane is recovered in the bottom stream. The top stream

Low temperature and distillation systems

249

from this stage is mainly methane, with some carryover of propane and heavier components. This stream is treated in a fourth column, again with the C51 additive stream injected as an absorbent to remove the C31 and yield a methane, sales gas top stream and an additive bottom stream that is recycled. Although ethane recovery from the bottom stream of the CO2 recovery column is desirable, simple distillation is ineffective due to the azeotrope formation. Other conventional methods of CO2 removal such as chemical absorption using amine solutions and adsorption using molecular sieves are capital-intensive, operationally complex, and generally not economically viable. Consequently, the CO2 plus ethane stream is commonly reinjected into the EOR reservoir, although membrane techniques for CO2
ethane separation have also been investigated and demonstrated on a pilot scale (Chapter 8). A number of other cryogenic fractionation methods with similarities to the Ryan
Holmes process have been developed for natural gas processing, including the Controlled Freeze Zone CFZt method developed by ExxonMobil, CryoCells developed by Cool Energy Inc. and Shell, and the SprexsCO2 technology developed by Total, IFP, and Prosernat (see Resources).

9.6

RD&D in cryogenic and distillation technologies

9.6.1 Traditional cryogenic and distillation system RD&D These technologies have been applied in industrial-scale processes for over a century and the technology can therefore be considered mature. As a result, ongoing RD&D effort is largely directed at optimizing cost and performance rather than targeting fundamental breakthroughs. High-performance process control, ensuring optimal plant operation to improve reliability and energy efficiency, is particularly important in reducing the penalty incurred by energy-intensive cryogenic separation systems. Approaches to the control problem range from detailed mathematical compositional modeling of the separation process that is used to derive model-based predictive or adaptive control, to model free adaptive control systems in which the control system adaptively learns how to optimize product yield and quality, and to maintain operational stability and efficiency. Increasing single-train capacity is also a development focus, in order to achieve lower unit production costs. Single-train ASU capacity has grown from B1.5 kt-O2/day in 1990 to B7 kt-O2/day currently, achieving significant cost reduction through economies of scale. Opportunities to achieve tighter process integration are also being investigated in order to improve energy and process efficiency. In one commercially demonstrated example, shown in Figure 9.24, integration with a gas turbine power generator reduced the inlet compression power requirement of the ASU by extracting air from the gas turbine air supply (air integration), while injection of the nitrogen top stream into the turbine combustor enabled increased power output without

250

Carbon Capture and Storage

Fuel

Combustion Gas turbine power plant

Air compression

Heat recovery Air Nitrogen integration Air integration Air compression

N2 Air separation unit

Oxygen Nitrogen

Figure 9.24 ASU process integration with gas turbine.

exceeding the turbine inlet temperature limit (nitrogen integration). NOx emissions were also reduced as a result of the lower combustion temperature. Preheating of the injected nitrogen was achieved by efficient recovery of low-level heat from the extracted air supply to the ASU.

9.6.2 Hydrate capture RD&D Two of the key disadvantages of hydrate-based capture are its high operating pressure, resulting in a large energy penalty, and large footprint required for the hydrate reactor. Ongoing RD&D focus areas, to address these and other challenges, include: G

G

G

G

G

Optimization of process parameters (e.g., hydrate number, slurry concentration, reactor temperature) to reduce energy penalty Identification of kinetic and thermodynamic promoters and other additives to reduce operating pressure while sustaining hydrate formation rate and overall process efficiency Evaluation of novel additives to promote hydrate formation (e.g., dry water, hydrophobic particles) Advanced process integration, for example, with seawater desalination, to improve overall efficiency Optimization of fixed bed hydrate reactor performance—packing material type, particle and pore size distribution, to reduce reactor footprint

9.7

Cryogenic carbon storage

The presence of a CO2 ice layer on the Martian polar icecaps led to a proposal to consider Antarctica as a possible storage location for solid CO2. Although still warm relative to the CO2 sublimation temperature of
78.5 C (at 1 bar), Antarctica, with a mean annual temperature of
57 C in the interior, would be the most suitable location to minimize the energy requirement of such a scheme.

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251

The envisaged system would capture CO2 by desublimation from ambient air blown into a 106 m3 cubic refrigeration plant cooled by liquid nitrogen. Each such deposition system could capture B250 t-CO2/h and would require 45 MW of power, notionally provided by an adjacent wind farm. The 40 cm depth of CO2 snow produced each day would then be compacted and stored in an insulated landfill, one such site (380 m 3 380 m 3 10 m) being required to hold the 2.2 Mt-CO2 produced each year. While space would clearly not be a constraint in scaling up (by multiplying deposition and storage units) to achieve capture rates of perhaps 1 GtCO2/year, the main challenge that such a scheme would have to overcome would undoubtedly be security of storage when compared to geological or ocean storage, given the constant energy input and stewardship required to prevent rapid release back into the atmosphere.

9.8

References and resources

9.8.1 References Agee, E., Orton, A., Rogers, J., 2013. CO2 snow deposition in Antarctica to curtail anthropogenic global warming. J. Appl. Meteorol. Climatol. 52, 281
288. Atsonios, K., Panopoulos, K.D., Doukelis, A., Koumanakos, A., Kakaras, E., 2013. Cryogenic method for H2 and CH4 recovery from a rich CO2 stream in pre-combustion carbon capture and storage schemes. Energy. 53, 106
113. Babu, P., Linga, P., Kumar, R., Englezos, P., 2015. A review of the hydrate based gas separation (HBGS) process for carbon dioxide pre-combustion capture. Energy. 85, 261
279. Clodic, D., M. Younes, 2002. A new method for CO2 capture: frosting CO2 at atmospheric pressure. Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies (GHGT6), Kyoto, Japan, 1
4 October, 2002. 155
160. Dashti, H., Yew, L.Z., Lou, X., 2015. Recent advances in gas hydrate-based CO2 capture. J. Nat. Gas Sci. Eng. 23, 195
207. Delgano, M.A., Diego, R., Alvarez, I., Ramos, J., Lockwood, F., 2014. CO2 balance in a compression and purification unit (CPU). Energy Procedia. 63, 322
331. Haase, D., et al., 2014. CO2 capture by cold membrane operation. Energy Procedia. 63, 186
193. Holmes, A.S., J.M. Ryan, 1979. Cryogenic Distillate Separation of Acid Gases from Methane. U.S. Patent 4,318,732-A. Kidnay, A.J., Parrish, W.R., 2006. Fundamentals of Natural Gas Processing. CRC Press, Boca Raton, FL. Kumar, R., Linga, P., Ripmeester, J.A., Englezos, P., 2009. Two-stage clathrate hydrate/ membrane process for precombustion capture of carbon dioxide and hydrogen. J. Environ. Eng. 135, 411
417. Latimer, R.E., 1967. Distillation of air. Chem. Eng. Prog. 63, 35
59. Linde Engineering Division, 2008. Cryogenic Air Separation; History and Technological Progress. Linde AG, Pullach, Germany. Linga, P., Kumar, R., Englezos, P., 2007. The clathrate hydrate process for post- and pre-combustion capture of carbon dioxide. J. Hazard. Mater. 149, 625
629. Meratla, Z., 1997. Combining cryogenic flue gas emission remediation with a CO2/O2 combustion cycle. Energy Convers. Manage. 38 (Suppl), S147
S152.

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Pichot, D., Granados, L., Morel, T., Schuller, A., Dubettier, R., Lockwood, F., 2017. Start-up of Port-Je´rˆome CRYOCAPt plant: optimised cryogenic CO2 capture from H2 plants. Energy Procedia. 114, 2682
2689. Radebaugh, R., 2009. Cryocoolers: the state of the art and recent developments. J. Phys. Condens. Matter. 21, 164219. Surovtseva, D., Amin, R., Barifcani, A., 2015. Design and operation of pilot plant for CO2 capture from IGCC flue gases by combined cryogenic and hydrate method. Chem. Eng. Res. Des. 89, 1752
1757. Xu, G., Jin, H., Yang, Y., Duan, L., Han, W., Gao, L., 2010. A novel coal-based hydrogen production system with low CO2 emissions. J. Eng. Gas Turbines Power. 132 (3), 31
701. Xu, C.G., Chen, Z.Y., Cai, J., Li, X.S., 2013. Study on pilot-scale CO2 separation from flue gas by the hydrate method. Energy Fuels. 28, 1242
1248.

9.8.2 Resources Air Liquide (Cryocapt, cryogenic precombustion capture technology): www.airliquide.com/ connected-innovation. ExxonMobil Inc. (CFZt natural gas processing technology): http://corporate.exxonmobil. com/en/technology/carbon-capture-and-sequestration/controlled-freeze-zone/controlledfreeze-zone-technology. Linde AG: www.linde-engineering.de/de/process_plants/index.html. Prosernat (SprexsCO2 natural gas processing technology): www.prosernat.com/en/solutions/ upstream/gas-sweetening/sprex.html.

Mineral carbonation

10

The aim of the carbon capture methods described in the previous chapters is to produce a pure or near-pure CO2 stream that can then be stored using one or other of the approaches described in Part II. As the discussion in the following chapters will show, storage as molecular CO2 has a number of consequences, ranging from the need for monitoring to confirm long-term storage integrity to the potential adverse environmental impacts in the case of ocean storage or leakage from geological storage sites. In contrast, approaches based on the processes of mineral carbonation seek to store carbon in the form of potentially useful products that are chemically stable and relatively benign. These processes mimic the slow, natural processes of weathering of igneous rocks and sequestration into long-term carbon sinks, and in this context “long-term” implies storage on a timescale of .100,000 years. The weathering of rocks and transportation of the products of weathering into the oceans were described in Chapter 1 as key steps in the geological carbon cycle. Mineral carbonation is a sequestration technology that accelerates this natural process and involves the reaction of CO2 with minerals containing oxides or silicates of magnesium, iron, and calcium to form stable carbonates. This can either occur in situ, with CO2 being transported to storage sites and injected into sub-surface formations rich in these minerals, or ex situ, using mined and pretreated minerals or a variety of industrial wastes as the source of cations for carbonation in engineered reactors. Biological mediation of carbonate formation is an important biogeological process which has had a major influence in shaping the earth, starting with the very earliest lifeforms at least 3.5 billion years ago. Inorganic carbonation reactions tend to progress slowly and, as discussed below, a major R&D focus continues to be on process steps such as mineral pre-treatment that enhance reaction kinetics. The employment of microorganisms, biocatalysts, or other biomimetic systems to accelerate carbonate deposition is another area of intensive research and rapid commercialization. The alternative term “carbon mineralization” is also used to describe equivalent chemical processes that exploit mineral alkalinity from a wide variety of wastederived feedstocks, ranging from combustion ash (waste incineration, shale oil combustion, etc.) to mine tailings and wastes from cement kilns and paper mills; the two terms—carbon mineralization and mineral carbonation—are used interchangeably here.

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00010-6 © 2017 Elsevier Inc. All rights reserved.

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10.1

Chemical and biological fundamentals

10.1.1 CO2 dissolution and hydration chemistry The starting point for most mineral carbonation processes, as well as for the geochemical trapping mechanism to be discussed in Chapter 14, is the dissolution and hydration of CO2 to form carbonic acid: CO2 ðaqÞ 1 H2 O2H2 CO3

(10.1)

In the following discussion the solutions are assumed to be ideal, so that activity coefficients are unity for all ions and ionic strength is a function of ion concentration (see Glossary—Ionic strength for an explanation of this approximation). The equilibrium constant for Reaction (10.1), known as the hydration equilibrium constant (Kh), will then measure the relative concentrations of product and reactant: Kh 5 ½H2 CO3 =½CO2  5 1:15 1023 at 30 C

ðlogKh30 5 22:94Þ

(10.2)

Note that [H2O] may be either included or excluded in defining and applying Kh—in this case it is excluded. Equation (10.2) shows that only 0.1% of the total dissolved CO2 is converted to H2CO3. Carbonic acid is a weak diprotic acid, meaning that it will yield two protons under successive dissociations: H2 CO3 2H1 1 HCO2 3

(10.3)

1 22 HCO2 3 2H 1 CO3

(10.4)

The equilibrium constants for these “deprotonations,” known as the acid dissociation constants, Ka1 and Ka2, measure the strength of the acid in solution and are given in terms of equilibrium concentrations by: 1 Ka1 5 ½HCO2 3 ½H =½H2 CO3 

(10.5)

1 2 Ka2 5 ½CO22 3 ½H =½HCO3 

(10.6)

and

These constants are often expressed in logarithmic form as: pKa 5 2logKa

(10.7)

and at 30 C the values are pKa1 5 6.33, pKa2 5 10.29, which fall within the weak acid range 2 , pKa , 12. Note that pKa is related to pH via the HendersonHasselbalch equation:
pH 5 pKa1 1 log ½HCO2 3 =½H2 CO3 

(10.8)

Mineral carbonation

255

KW CO2 (aq) + OH–

CO2 (aq) + H2O H+ k1

k–1 (K1)

k2

k–2 (K2)

Ka2 H2CO3

Ka1 HCO3–

H+

CO32–

H+

Figure 10.1 Reaction scheme of CO2 in aqueous solutions. Source: After Wang et al. (2010).

–2 Log (Concentration) (mol/L)

Common natural waters H2CO3

*

CO32–

HCO3–

–3

–4

–5

pH = pKa1 (6.33)

pH = pKa2 (10.29)

–6 2

4

6

8

10

12

14

pH

Figure 10.2 Relative distribution of carbon species versus pH.

which immediately follows from taking the log of both sides of Equation (10.5). Similarly, 2 pH 5 pKa2 1 log ½CO22 3 =½HCO3 




(10.9)

Under alkaline conditions, the bicarbonate ion will also be produced via: CO2ðaqÞ 1 OH2 2HCO2 3

(10.10)

The overall reaction scheme is shown in Figure 10.1, where Kw, the dissociation constant of water is the equilibrium constant of the reaction: H2 O2H1 1 OH2 ðor its equivalent 2H2 O2H3 O1 1 OH2 Þ

(10.11)

By combining these equilibrium constants, the distribution of carbon among the different species can be calculated as a function of the overall solution pH.

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Carbon Capture and Storage

Figure 10.2 shows the relative distributions in a solution with total inorganic carbon content of 1023 mol/L. Note that CO2(aq) and H2CO3 are conventionally combined and denoted H2CO3 . The curves cross at pH 5 pKa1, where ½CO2  5 ½HCO2 3 , and 22 at pH 5 pKa2, where ½HCO2  5 ½CO . 3 3 From the figure it can be seen that for most natural waters, with pH of 68, most carbon is present in the form of the bicarbonate ion, while higher carbonate ion concentration, which is required for carbonate precipitation, occurs for a pH of 10 and above. This distribution will also be important in the following chapter, in distinguishing solubility trapping (CO2 trapped at H2CO3 below a pH of 6.35) and ionic trapping (CO2 trapped as bicarbonate or carbonate ions at higher pH).

10.1.2 Mineral carbonation chemistry The simplest carbonation reaction occurs when a metal oxide, such as magnesium oxide, is reacted with CO2 to yield magnesium carbonate: MgO 1 CO2 ! MgCO3 1 heat

(10.12)

The stability of the carbonate reaction product over geological timescales results from the fact that a carbon atom in a carbonate is in its lowest energy state (Figure 10.3), and the thermodynamic consequence is that the carbonation reaction is exothermic, the excess energy (60180 kJ/mol depending on the mineral reactant) being released as heat. This gives mineral carbonation an inherent energetic advantage over options such as geological storage, where CO2 is stored as a supercritical fluid, since the reaction heat can be recovered to power other process steps. Calcium or magnesium oxides would be ideal candidates as mineral feedstocks for carbonation, since their carbonates (CaCO3, MgCO3) have low solubility in water. This is an important consideration if the carbonation products would ultimately be stored on land (e.g., back-filling an open cast mine) in order to prevent ground water contamination through leaching. However, as described below, the carbonation reaction typically requires some 23 tonnes of mineral input per tonne of CO2 sequestered. Natural abundance is therefore an important characteristic for a suitable feed mineral, and these oxides are rare in nature as a result of their reactivity. Carbon

400 KJ/mol

Combustion

Carbon dioxide 60–180 KJ/mol

Figure 10.3 Energy states of carbon.

Carbonation Carbonate

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257

Silicate rocks are an alternative source of metal oxides and make up the majority of the earth’s mantle. In particular, mafic and ultramafic rocks are igneous silicate rocks that consist predominantly of magnesium, calcium, and iron minerals. Silicate minerals occurring in these rocks include olivine ((Fex, Mg12x)2SiO4), wollastonite (CaSiO3), and serpentine (Mg3Si2O5(OH)4). In the case of olivine (Fex, Mg12x) in the chemical formula indicates that the mineral is a mixture (known as a solid solution) of iron and magnesium silicates, with forsterite (Mg2SiO4) and fayalite (Fe2SiO4) being the pure end-members of this range. The three minerals noted above are representatives of different classes of silicates, which are defined according to the way the silicate ion ðSiO42 4 Þ is bonded in the crystal lattice. Orthosilicate minerals, of which olivine is an example, have the simplest structure and consist of a single SiO42 4 anion bonded to two divalent metal cations (Mg21 or Fe21). In contrast, pyroxenes form single chains as a result of the sharing of an oxygen atom between two SiO4 units. Wollastonite is an example of a single-chain silicate. Serpentine is an example of the more complex class of phyllo(or leaf-like) silicates, with sheet-like structures in which three of the four oxygen atoms from each SiO4 unit are shared with adjacent units to form hexagonal rings that extend into sheets (Figure 10.4). In minerals containing hydroxyl ions (OH2), including serpentine, the OH2 ions bond at the center of the hexagonal ring. Metal cations form bonds with oxygen and hydroxyl to form a second, parallel sheet in which each metal ion is surrounded by eight oxygen or hydroxyl ions. Figure 10.5 shows the resulting lamellar structure for the lizardite form of serpentine. In some cases, including the antigorite and chrysotile forms of serpentine, the combined two-sheet structure takes up a curved form as a result of the longer spacing of the metal ion layer compared to the Si2O5 layer. Chrysotile (asbestos) is an extreme example of this curvature in which the structure is rolled up to form fibers. The different structures of these minerals have an impact on the relative ease with which they react with CO2, necessitating various pre-treatment options described later. The carbonation reactions for a number of minerals that have been considered as possible candidates for CCS are shown in Reactions (10.13)(10.16). Olivine (forsterite) Mg2 SiO4 1 2CO2 ! 2MgCO3 1 SiO2

(10.13)

Si2O5–2

SiO3 tetrahedra

Figure 10.4 Si2O5 sheet structure of phyllosilicate minerals.

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Carbon Capture and Storage

O– Silicate SiO3 tetrahedra

Si4+ OH–

Brucite Mg(OH)2 octahedra

Mg2+ (A)

(B)

Planar lizardite plates

Curved antigorite plates

Figure 10.5 Structure of the sheet silicate serpentine: (A) lizardite and (B) antigorite.

Olivine (fayalite) Fe2 SiO4 1 2CO2 ! 2FeCO3 1 SiO2

(10.14)

Wollastonite CaSiO3 1 CO2 ! CaCO3 1 SiO2

(10.15)

Serpentine Mg3 Si2 O5 ðOHÞ4 1 3CO2 ! 3MgCO3 1 2SiO2 1 2H2 O

(10.16)

In an aqueous reaction, the second end product will generally be orthosilicic acid (H4SiO4) rather than silicon dioxide (SiO2). The enthalpy of reaction from carbonation of these minerals is compared in Table 10.1 to the heat initially released in the combustion of carbon to produce a mole of CO2 ðC 1 O2 ! CO2 Þ. Clearly the enthalpy of reaction is a significant fraction of the initial heat from combustion, and the effective use of this heat will reduce the energy and carbon penalty of the carbonation process. Although the carbonation reactions are thermodynamically favored, the reactions shown above proceed at very slow rates at room temperature and pressure, due to the slow dissolution of the metal from the mineral lattice. A major focus of research work has therefore been on chemical process optimization to achieve reaction rates that are viable for industrial applications. Several chemical process options have been considered, including methods where CO2 is reacted directly with the mineral feedstock, and indirect methods where the reactive mineral component is extracted from the feedstock in an initial

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259

Table 10.1 Heat released in carbonation reactions Mineral

Enthalpy of reaction 2ΔH0r (kJ/mol)

% of heat from carbon combustion (2ΔHr/393.8)%

Calcium oxide (CaO) Magnesium oxide (MgO) Olivine (forsterite) Wollastonite Serpentine

179 118 89 87 64

45% 30% 23% 22% 16%

Table 10.2 Potential carbonation reaction routes Reaction route

Options

Sub-options

Direct carbonation

Dry gassolid reaction

Gaseous CO2 Supercritical CO2 With or without additives pH swing—two-step aqueous route Hydrochloric acid Sulfuric acid Acetic acid

Aqueous reaction Indirect carbonation

Acid extraction

Molten salt extraction Sodium hydroxide

step to improve the reaction rate. Following the initial extraction step, the reactive component can be carbonated using any of the direct route options. These options are summarized in Table 10.2 and described below.

10.1.3 Biomineralization The production of minerals by living organisms is widespread in nature, with end products ranging from coral and mollusk shells to bones and teeth. These processes are collectively called biomineralization, and two general types occur. In biologically controlled mineralization (BCM), mineral synthesis takes place either within or on the surface of the cell, at a specific location under the control of the organism, while in biologically induced mineralization (BIM) mineral deposition takes place outside the cell as a result of the organism’s metabolic activity. Simplistically, in

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Carbon Capture and Storage

BCM mineral synthesis is an objective of the process while in BIM the mineral deposit is a by-product. Induced mineralization processes have been widely studied, with potential applications from wastewater cleanup and bioremediation of environmental pollution (phycoremediation) to the fabrication and strengthening of building materials and ground consolidation. The biologically induced precipitation of calcium carbonate is a carbon mineralization process that also has potential application in carbon capture.

Calcite precipitation by cyanobacteria Cyanobacteria (blue-green algae) are among the oldest lifeforms on earth, and their photosynthetic activity played a central role in the oxygenation of the ocean and atmosphere that was a precursor to the Cambrian explosion, some 540 million years ago. Calcite precipitation by cyanobacteria and other microorganisms—in the form of stromatolites—is common in the geological record stretching back at least 3.5 billion years. Whether there is a physiological reason for this induced mineralization—for example, related to the need to control calcium levels inside the cell—or whether it is simply a result of alkalinity increase in their environment as a result of CO2 removal is still under debate. Recent work does however suggest that functional groups on the cell surface provide a template for calcite crystallization— an indication that extracellular mineralization benefits the organism, and that at least some cyanobacterial strains also produce intra-cellular calcite—possibly indicative of a controlled (BCM) rather than an induced (BIM) process. The extracellular mineralization process, shown schematically in Figure 10.6, involves the following inorganic chemical reactions: firstly the dissolution of CO2 Cell membranes HCO3– Carbonic anhydrase

Carboxysome

HCO3–

CO2 RuBisCO

CO2

Alkalinization of the cell microenvironment

OH– HCO3– Carbonate anion and H2O metal cation supply CO32– Ca2+

Nucleation sites

CaCO3

Figure 10.6 Extracellular biomineralization in cyanobacteria. Source: After Power et al. (2013).

Carbonate precipitation

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261

in the aqueous environment to form carbonic acid and its dissociation to bicarbonate ions and protons (Reaction (10.17)); (CA—see next section) plays an important part in this initial step of bicarbonate ion formation. Bicarbonate ions are then transported into the cell and provide the carbon dioxide needed for photosynthesis, CA again playing an important role in concentrating CO2 within the cell. Hydroxy ions are formed within the cell as a by-product of the dehydration of bicarbonate ions by CA in the carboxysome (where photosynthesis takes place). These are transported out of the cell and react with bicarbonate ions in the aqueous environment: 1 22 OH 1 HCO2 3 ! H 1 CO3

(10.17)

Finally, the carbonate anion combines with a calcium or magnesium cation from the aqueous medium, transported from within the cell or desorbed from the cell wall, and calcite is precipitated: Ca21 1 CO22 3 ! CaCO3 k

(10.18)

The last step is facilitated by carboxyl and amine functional groups on the cell surface which provide nucleation sites for crystallization. The carbon mineralization ability of cyanobacteria is being studied as a potential capture technology that could either be combined with microalgal biomass production for biofuel synthesis (see Section 22.2), providing two parallel capture routes as shown in Figure 10.7, or deployed as an engineered biomimetic capture process. The scope of current research includes: G

G

G

G

The physiological functions achieved by mineralization The stages and controls on the mineralization process (e.g., nucleation at functional sites, crystallization, and crystal morphology and aggregation) The interaction of photosynthetic production and mineralization The genetic profiles affecting mineralization capacity of various bacterial strains under varying environmental conditions

the overall aim being to provide the fundamental understanding necessary to engineer a viable industrial process, possibly including the genetic engineering or directed evolution of optimal bacterial strains.

CO2

Photosynthesis Organic carbon capture

Biomass

CO2

Biomineralization Inorganic carbon capture

CaCO3

Figure 10.7 Potential parallel carbon capture paths using cyanobacteria.

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Carbon Capture and Storage

Apart from the photosynthetic related BIM seen in cyanobacteria, calcite is also deposited by other bacteria, such as ureolytic bacteria commonly found in soils, which metabolize urea as a source of nitrogen, producing calcite as a by-product. This process, in which urea (CO(NH2)2) is hydrolyzed to ammonia (NH4) and carbonate ions (CO321), is the basis of the microbially induced calcium carbonate precipitation (MICCP) process, which has found application in the construction industry and has potential applications in geological storage for remediation of leakage paths in well cement, microfractures, and permeable caprock (see Part III).

Biocatalytic carbon mineralization When the calcite precipitation process described above takes place in seawater, without biological mediation, the formation of bicarbonate ions ðHCO2 3 Þ is the rate-limiting step. In order to accelerate the process of biomineral formation, a family of enzymes has evolved in a wide range of organisms that catalyze the hydration of CO2 to HCO2 3 . These enzymes, collectively known as carbonic anhydrases, are metalloenzymes—meaning that the active site contains a metal ion (commonly zinc). The catalyzed hydration mechanism is illustrated in Figure 10.8. The figure shows the active site—the zinc atom—which is held in place by bonds to three amino acids (histidines—His94, etc.). The complex organic form of the anhydrase enzyme, which includes a pocket or cleft that specifically accommodates a CO2 molecule—bringing it close to the active site, is omitted for clarity. O H H+

(3)

H

O–

His94

(2)

CO2

Zn2+

His119

C

O–

O

O–

His94

O

Zn2+

His119

(1)

H

His94

O

O– C

O

His94

HCO3–

Zn2+

His119

His94

His119

His96

O

O

C

Zn2+

His96

H H

H

Zn2+

His96

H2O

Figure 10.8 Biocatalyzed hydration of CO2 by CA. Source: After Lee (2010).

His119

(5)

His96

(4)

His96

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263

The chemical bonding geometry of zinc in CA is tetrahedral (known as tetrahedral coordination) and in the first step of the hydration process(1 in the figure) the fourth coordination position is occupied by a water molecule. Polarization of the water molecule weakens the HO bonds and a fourth histidine (His64), located close to the water, accepts a proton (H1) and transfers it to the bulk solution, leaving a hydroxide attached to the zinc (2). A CO2 molecule can then enter the active space and the excess electron from the OH2 ion transfers to the CO2 (3) causing a realignment of the CO bonds and the formation of a zinc-bound bicarbonate (4). After isomerization (5—the shift of the H to the nonzinc-bound oxygen), the scene is set for the release of the bicarbonate ion and its replacement by a new water molecule (1). For several types of CA, including the human variety hCAII, each CA molecule can execute this elegant mechanism more than 106 times per second, many orders of magnitude faster that in the absence of a catalyst. Once the bicarbonate ion is released into a bulk medium containing calcium ions, calcite precipitation can proceed according to Reactions (10.17) and (10.18). Experimental investigations into the use of CA to catalyze the carbon mineralization in artificial seawater began in the 1990s, and intensive research since then has focused on sustaining catalytic activity at industry relevant temperatures, including the identification and extraction of suitable CA from microorganisms and the chemical or physical immobilization of the catalyst to increase stability and longevity while sustaining performance by ensuring that the active site remains accessible. The commercial potential of this technology has driven rapid R&D progress and has led to a number of proprietary systems being developed and demonstrated at laboratory scale. Ongoing research, much of it aimed at the application of CA to enhance CO2 absorption systems (see Chapter 6), continues to focus inter alia on: G

G

G

G

G

Characterization of thermostable CAs, typically isolated from thermophilic microorganisms Improvement of immobilization techniques Protein engineering of wild-type CAs to improve thermal stability Preparation and characterization of novel catalytic molecules to mimic enzyme activity Investigation of biological processes such as rapid repair of damaged shell by mollusks

10.2

Direct carbonation routes

10.2.1 Direct gassolid carbonation The direct carbonation of a solid mineral in gaseous CO2 (shown, e.g., for direct olivine carbonation in Reaction (10.13)) is the simplest carbonation reaction in terms of the process design and offers the best prospect of effective utilization of the heat released in the reaction. However, using silicate minerals the reaction rate is too slow for industrial-scale application, even at elevated temperatures and pressures (e.g., using supercritical CO2 at 1015 MPa).

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The direct gassolid reaction is however a viable carbonation route if the alkalineearth metal is first extracted from the silicate feedstock as an oxide or hydroxide, since the carbonation of these compounds is rapid. For example: MgðOHÞ2 1 CO2 ! MgCO3 1 H2 O

(10.19)

The feasibility of the initial extraction step is discussed under the indirect reaction route below. This route has also been proposed for the carbonation of bag house dust—a by-product of steelmaking—which comprises .85% oxides of Fe, Ca, and Mg and typically has a median particle size of B100 μm. In this case the gassolid route has the advantage that it avoids the leaching of heavy metals such as lead, chromium, and cadmium that cause this material to be classified as a hazardous waste. Carbonation can also lead to the encapsulation and immobilization of these metals, making the end product less hazardous.

10.2.2 Direct aqueous carbonation Direct carbonation in an aqueous medium is considered by many research groups as the most promising reaction route and has been the subject of extensive research effort. The presence of water speeds up the carbonation reaction, which then proceeds in three steps; for example, for forsterite olivine: 1. CO2 dissolves in water to form carbonic acid containing protons (H1) and bicarbonate ions (HCO32): CO2 1 H2 O ! H2 CO3 ! H1 1 HCO2 3

(10.20)

2. The presence of free protons (H1) enables the release of Ca and Mg from the mineral matrix: Mg2 SiO4 1 4H1 ! 2Mg21 1 SiO2 1 2H2 O

(10.21)

3. The metal and bicarbonate ions combine to precipitate carbonate: 1 Mg21 1 HCO2 3 ! MgCO3 1 H

(10.22)

Without the use of additives, the rate-limiting step in this reaction is the release of metal ions from the mineral matrix, and the speed of the reaction can generally be increased by decreasing the mineral particle size, for example, by fine grinding, thereby increasing the surface area available for the reaction. The use of additives, such as sodium chloride (NaCl) citrate (Na3C6H5O7), oxalate (Na2C2O4), and EDTA (C10H16N2O8), can also enhance the release of metal ions from the silicate. The deposition of an inert SiO2 surface layer on mineral particles also inhibits metal ion release and can be reduced by attrition through vigorous stirring or ultrasonic

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265

agitation (“sonication”), although at significant additional energy cost. Under these conditions formation of the bicarbonate ion after CO2 dissolution (Reaction (10.20)) can become rate-limiting, and CA has been used to catalyze this hydration step. Dissolution of the metal ion from the mineral feedstock (Reaction (10.21)) requires a low pH, while a higher pH is optimal for the precipitation step (Reaction (10.22)). This has led to the so-called pH swing option in which the pH is varied as the reaction proceeds, to achieve optimal conditions for each step. This and other aspects of reaction optimization are discussed in Section 10.4. In situ mineral carbonation is one example of an aqueous direct carbonation process. This involves the injection of CO2 through wells into a suitable formation—of which the Samail Ophiolite, in the Sultanate of Oman, the Juan de Fuca plate basalts, offshore USA, and Iceland, in its entirety, are well-studied examples. Because in situ carbonation increases solid mass in the sub-surface, the process may be hindered due to: G

G

G

Reduced pore network permeability due to carbonate deposition in pores Reduced fracture system permeability due to carbonate deposition or compaction as a result of the increased solid mass Reduced reactivity due to deposition onto mineral surfaces

Alternatively, depending on the in situ stresses, volume change due to mineral hydration may result in reaction-driven fracturing that could increase permeability and expose new reactive surfaces. Assessing these potential feedback mechanisms will require site-specific pilot testing.

10.2.3 Direct carbonation in seawater and other brines In the aqueous carbonation route, the rate-limiting step of releasing metal ions from a mineral matrix can also be bypassed if a ready-made solution containing suitable cations is available in sufficient quantities. Seawater is one such solution and contains B1400 mg/L of Mg21 and B400 mg/L of Ca21 cations. One km3 of seawater could therefore sequester B2.5 Mt-CO2 as nesquehonite (Mg(OH)(HCO3)  2H2O) and calcite (CaCO3) precipitates. Other potential sources of metal cations for carbon mineralization include aqueous waste streams such as produced water associated with oil and gas operations and reject brine from seawater desalination plants.

10.2.4 Direct carbonation in soils The use of olivine as a soil amendment to capture CO2 from the atmosphere in an enhanced weathering process has also been proposed. Laboratory investigations using cored soil profiles showed that forsterite-rich olivine dissolution rates similar to those seen in volcanic island arc could be achieved, for one set of experimental conditions (soil type, “precipitation” rate, temperature, etc.). However, achieving rapid mineralization, for example, converting all applied mineral within 5 years, would require grinding to a particle size of ,1 μm, with an energy

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requirement of B1 GJ/t-mineral and an overall penalty of B6 GJ/t-CO2, well above other direct air capture methods under development.

10.3

Indirect carbonation routes

A wide variety of indirect carbonation options have been proposed that are based on the application of acids to extract the alkalineearth metal from the mineral feedstock, and either precipitate this as a more reactive hydroxide for carbonation in a second step, or carbonate the metal ion directly in solution.

10.3.1 Indirect carbonation by acid extraction The use of hydrochloric acid (HCl) was the first such approach proposed and, with a serpentine feedstock, proceeds according to the following steps: 1. HCl is used to extract magnesium as magnesium chloride: Mg3 Si2 O5 ðOHÞ4 1 6HCl 1 H2 O ! 3MgCl2U6H2 O 1 2SiO2

(10.23)

2. HCl is recovered by heating the solution to B250 C: MgCl2  6H2 O ! MgClðOHÞ 1 HCl 1 5H2 O

(10.24)

3. Water is introduced to reform MgCl(OH) to Mg(OH)2 which is precipitated:

2MgClðOHÞ ! MgðOHÞ2 1 Mg2 Cl2

(10.25)

The precipitated hydroxide is then carbonated via the direct carbonation step in Reaction (10.19). The energy cost of Step 2 in this extraction route is very high and has been estimated as four times the energy released by carbon combustion for the quantity of CO2 eventually sequestered. Clearly, without a substantial reduction in energy requirements this is not a feasible sequestration process. A similar route has been proposed using sulfuric acid, either forming magnesium hydroxide for carbonation as in the HCl route, or carbonating the magnesium sulfate directly in solution according to: Mg3 Si2 O5 ðOHÞ4 1 3H2 SO4 ! 3MgSO4 1 5H2 O 1 2SiO2

(10.26)

followed by: 3MgSO4 1 3H2 O 1 2SiO2 1 3CO2 ! 3MgCO3 1 2SiO2 1 3H2 SO4

(10.27)

Although in principle these reaction routes result in recovery of the acids, some makeup volume of acid is likely in practice. This would be required, for example,

Mineral carbonation

267

if the feedstock contains alkali metals, which would react with HCl to form soluble chlorides, consuming chlorine. The sulfuric acid process does not require the energy-intensive dehydration step that was necessary for HCl extraction, but would also require acid makeup. The use of acids would also increase the construction cost of a carbonation reactor in view of the need to use more corrosion-resistant materials. Acetic acid extraction has also been proposed, using wollastonite as a feedstock to produce calcium carbonate. This has the advantage of being a less corrosive medium and therefore puts less stringent constraints on reactor material selection, although laboratory trials indicate that recovery of the acetic acid may be problematic.

10.3.2 Indirect carbonation by ammonium sulfate extraction ˚ bo Akademi A promising indirect carbonation route has been developed at the A ˚ University (AAU) in Finland, using ammonium sulfate in a multi-step to produce magnesium hydroxide. Milled silicate rock is first heated at 450 C with ammonium sulfate (NH4)2SO4 to produce magnesium sulfate: Mg3 Si2 O5 ðOHÞ4 1 3ðNH4 Þ2 SO4 23MgSO4 1 2SiO2 1 5H2 O 1 6NH3 (10.28) The solids are mixed with water and the insoluble rock residue is removed. Ammonia released in this step is used to raise the solution pH, first to B78 in order to precipitate iron oxyhydroxide (FeOOH—goethite) from sulfates that will have formed from iron silicate components in the rock. This by-product can be used for iron making. The pH is further raised by additional ammonia dissolution to B1011 and magnesium precipitates as Mg(OH)2: MgSO4 1 2NH4 OH2ðNH4 Þ2 SO4 1 MgðOHÞ2

(10.29)

Finally, ammonium sulfate is recovered from the solution either by complete evaporation using heat recovery from flue gases or, with greater energy efficiency, using mechanical vapor recompression (see Glossary). The Mg(OH)2 is then carbonated in a fluidized bed to capture CO2 from postcombustion flue gases from a lime kiln or power plant. The overall process is shown schematically in Figure 10.9. This route is being considered for pilot-scale application at a 100 t/day lime kiln at Parainen, Finland. Heat recovery from the kiln is sufficient to process 13.2 t/day of serpentine rock; with 80% Mg extraction and 90% Mg(OH)2 carbonation this would result in capture of B4.5 t-CO2/day. External electrical energy input of 0.8 GJ/t-CO2 captured would also be required for rock crushing/grinding and gas compression.

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Process heat

Magnesium silicate

Solid–solid reactor Ammonium sulfate recycle

Steam NH3

Water

MgSO4

Mg and Fe extraction

etc.

Silica and rock residue

Mg(OH)2

Steam activation MgCO3

PFB (>2MPa, >500°C)

Iron oxide to steel industry

CO2

Figure 10.9 Mineral carbonation by ammonium sulfate extraction.

10.3.3 Indirect carbonation by other extraction methods Molten salt extraction The use of a molten salt, such as magnesium chloride, as an extraction medium can partially reduce the energy cost of the dehydration step in the HCl extraction option. In its simplest form, the carbonation reaction takes place in a single direct step in a molten salt medium (MgCl2  3.5H2O) at B200 C. Alternatively, a multistep process similar to HCl extraction can be used, with the intermediate precipitation, separation, and carbonation of magnesium hydroxide. Once again, the energy cost and corrosive nature of the extraction medium are challenges for this option.

Sodium hydroxide extraction The use of sodium hydroxide has also been proposed as an alternative to acid extraction. In this option calcium or magnesium is released from the mineral matrix and precipitated as hydroxide, with sodium taking the place of the extracted metal ion in the mineral. For example, with plagioclase (calcium feldspar) as a feedstock, the overall reaction is: 3CaAl2 Si2 O8 1 8NaOH 1 4CO2 ! 3CaCO3 1 Na8 ðAlSiO4 Þ6 CO3  2H2 O 1 2H2 O (10.30) Since sodium hydroxide is consumed in the reaction, substantial quantities (1.8 t-NaOH/t-CO2) would be required if this reaction route were to be applied on an industrial scale.

10.4

Technology development status

A technology development road map for mineral carbonation is shown in Table 10.3. The technology is currently at the development stage, with a wide range of applied research studies being conducted.

Mineral carbonation

269

Table 10.3 Technology development road map for mineral carbonation

Research Identification of preferred mineral feedstock Assessment of global availability of preferred mineral resources

Development Optimization of direct versus indirect, and gassolid versus aqueous reaction optionsAssessment and optimization of mineral pre-treatment and activation options (mechanical, thermal, chemical, electromagnetic) Increasing reaction rate through optimization of reaction parameters (CO2 partial pressure, reaction temperature, solution additives, agitation leading to particle abrasion, etc.) Assessment of in situ versus ex situ carbonation options Use of alkaline solid waste as a feedstock and integration with industrial processes Assessment of disposal and reuse options for carbonation end products Design and development of a demonstration-scale carbonation reactor Assessment of economic feasibility

Demonstration (possible example demonstrator projects) Carbonation of steel mill slag, mine tailings, and other industrial wastes Coal gasification, liquid fuel synthesis with integrated mineral carbonation Power plant, pre-combustion CO2 capture and integrated mineral carbonation

Deployment Integrated mineral carbonation

The following sections summarize some of the key issues addressed and outcomes to date.

10.4.1 Identification of preferred mineral feedstock A number of important characteristics can be identified that would need to be fulfilled by the optimal feedstock for mineral carbonation: G

G

G

G

G

Low cost of supply and preparation High reaction rate, either natural or achievable with reaction optimization Availability and global distribution High molar fraction of alkalineearth metal Low reaction energy requirements

Low cost of supply and preparation is essential, since typically 23 t of mineral feedstock are required to capture 1 t-CO2. Costs therefore cannot exceed a few US$ per tonne. Supply and preparation steps include mining, transportation, grinding, and removal of any impurities or components that would impede the carbonation reaction or cause problems in storing the reaction products (e.g., components that could leach out of mine back-filling). Many olivines and serpentines contain 5%20% by weight of iron oxides, a valuable by-product that can reduce the net cost of the feedstock.

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Table 10.4 Relative mineral feedstock quantities and conversion efficiencies Mineral Olivine (forsterite) Olivine (fayalite) Wollastonite Serpentine (lizardite) Serpentine (antigorite)

RCO2 (kg/kg) 1.61.8 2.32.8 2.62.8 2.12.1 2.12.5

RC (kg/kg) 5.96.6 8.410.3 9.510.3 7.77.7 7.79.2

Rx (%) 6080 6065 4080 940 6090

A high reaction rate, either natural or through reaction optimization, is essential to accelerate the carbonation reaction from a geological to an industrial timescale. While the carbonation reaction is faster for the alkali metals such as sodium and potassium than for the alkalineearth metals calcium and magnesium, the higher reactivities of sodium and potassium also result in their carbonates being soluble in water. This would pose problems for storage of reaction products. Of the alkalineearth metals, the carbonation reaction proceeds faster for calcium than for magnesium, as is indicated by the greater heat release in the exothermic carbonation of CaO (ΔH0r 5 2179 kJ/mol) compared to MgO (ΔH0r 5 2118 kJ/mol). For a given carbonation feedstock, the efficiency of the carbonation reaction is expressed by the parameter Rx, which measures the percentage conversion of available metal cations into carbonate. The conversion efficiency depends on the specific reaction conditions (temperature, pressure, time) and mineral pre-treatment. The Rx values shown in Table 10.4 for each mineral illustrate the range of values achieved in various experiments, the lower figure without and the higher figure with activation, either by ultrafine grinding or by heat or other pre-treatment. Availability and global distribution is clearly very important for a feedstock if mineral carbonation is to be applied on an impact scale. Of the alkalineearth silicates, olivine and serpentine occur in nature in vast quantities. The igneous rocks that contain these minerals originated from upwelling magma on ancient ocean floors, and several countries, including the United States and Oman, have sufficient deposits to store the CO2 generated from combustion of a greater part of the world’s coal reserves. Studies of deposits within the United States have shown a good match on a regional scale between the distribution of these resources and the regional CO2 emissions from coal-fired power plants. In other countries, costeffective exploitation of the available mineral resources may require the development of a CO2 pipeline infrastructure to transport captured CO2 to carbonation plants located at major mineral deposits. A high molar fraction of alkalineearth metal in the feedstock will minimize the quantity of rock that needs to be mined per t-CO2 captured. Two ratios commonly used to compare the amount of candidate feedstocks required to capture a certain quantity of CO2 are as follows: 1. RCO2: the quantity of mineral required to capture 1 t-CO2 2. RC: the quantity of mineral required to capture the CO2 produced by combustion of 1 t-C (equal to RCO2 times 44/12, the ratio of the molecular weights of CO2 and C)

Mineral carbonation

271

Table 10.5 Ranking of potential mineral carbonation feedstocks Characteristic

Olivine Serpentine Wollastonite Alkaline industrial waste

Cost of supply and preparation Reaction rate Availability Global distribution High molar fraction of alkalineearth metal Low reaction energy requirements

5 5 11 1 1

5 2 11 1 1

5 1 2 2 2

11 11 22 1 5

5

2

5

1

Note: 5 represents the basis for comparison;1 and11 imply better or much better performance against a particular characteristic; 2 and22 imply poorer performance.

These ratios are shown in Table 10.6 for some potential mineral feedstocks. RC and RCO2 are determined purely by the mineral feedstock composition and, in the case of a pure mineral, by the ratios of molecular weights. The table shows two RCO2 values for each mineral, first the theoretical value for a pure mineral and second a typical value for an actual prepared mineral sample. The RCO2 values show that the magnesium minerals (forsterite, lizardite) are more efficient in terms of quantities required, due to the lower molar weight of magnesium (24) versus calcium (40). Low reaction energy requirements will keep down the cost of the carbonation process and also contribute to its net capture efficiency by reducing CO2 emissions attributed to the process energy requirements. Olivine and wollastonite are slightly favored over serpentine due to the higher exothermic heat of reaction noted earlier, although the practicality of usefully applying this reaction heat in an integrated carbonation process is a subject for further investigation. If an indirect acid extraction method is used (Section 10.3.1), the carbonation reaction heat could be easily used in acid recovery (Reaction (10.24)). Table 10.5 compares a number of potential feedstocks for mineral carbonation using these characteristics. Based on these considerations, most development work has been focused on either olivine or serpentine as the likely feedstocks for large-scale application. Alternative feedstocks may also be important at the technology demonstration stage and for niche applications in specific industries, as discussed in the following section.

10.4.2 Alternative feedstocks and industrial integration Many industrial processes produce alkaline waste that could be used as a feedstock for mineral carbonation. Although these wastes are not available on the Gt scale that would be required for a carbonation feedstock on a global scale, the quantities are significant for the industries involved and their use as a carbonation feedstock

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could have advantages over the minerals considered earlier, including reducing the net emissions of these industries. The candidate alkaline wastes include: G

G

G

G

G

G

Municipal waste incinerator ash Ash from coal combustion Slag from steelmaking Ash and waste cement from cement production Waste concrete from building demolition Mine tailings (including old asbestos mines)

These materials contain a significant proportion of primarily calcium oxides and hydroxides (10%15% for concrete waste, 40%50% for steel slag) and can be carbonated using any of the reaction routes applied to mineral feedstock, direct aqueous carbonation being the front-runner. The use of these materials in a direct air capture system has also been considered and is described further in Section 22.1.1. Many of these wastes (e.g., steel slag and waste concrete) have a reuse value in the US$510/t range that is comparable to or exceeds the expected mined cost of mineral feedstocks. However, carbonation can in many cases be effectively integrated with the reuse process, adding value to the end product. Examples are the production of precipitated calcium carbonate (Section 22.1.1) or the reuse of steel slag as a cement additive. This process requires the slag to be crushed and finely ground, and these are also necessary preparation steps for carbonation. Integration of a carbonation step in the recycling process therefore would not incur additional preparation costs. A particular advantage of the use of asbestos (chrysotile serpentine) mine tailings is that the hazardous nature of the waste is effectively remediated by the carbonation reaction, which consumes the asbestos fibers. The quantity of asbestos mine tailings available globally is estimated to be in the range from 2 to 6 Gt, with a potential to sequester up to 2.5 Gt-CO2. Much of this is located in the United States and Canada, the Black Lake mine in Quebec, Canada, alone having a potential storage capacity of up to 0.7 Gt-CO2. While relatively few mines have such a large potential capacity, in many cases carbonation of tailings could fully offset emissions from mine operations while other environmental benefits may be a further important enabler for the use of this feedstock. Ongoing R&D work is focused on understanding the parameters affecting the carbonation of mine residues, such as the impact of liquid saturation, gas composition, and mineral heterogeneity.

10.4.3 Reaction optimization, including mineral pre-treatment and activation Investigations of the aqueous carbonation route have identified the optimal carrier solution for the reaction as a sodium bicarbonate plus sodium chloride solution with strength 0.64 M for NaHCO3 and 1 M for NaCl. (A 1 M, or Molar, solution contains 1 gram mole per liter of water. Thus a 0.64 M NaHCO3 solution contains

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53.8 g/L and a 1 M NaCl solution contains 58.4 g/L.) The addition of sodium bicarbonate increases the concentration of HCO32, accelerating the carbonation reaction (Reaction (10.22)). CO2 solubility is also increased by a factor of 20 in the optimal carrier solution (20 g/L vs ,1 g/L in distilled water), allowing the reaction to take place at lower CO2 pressure. Finally, the bicarbonatesalt mixture buffers the pH of the carrier solution to a slightly alkaline 7.78.0, aiding precipitation of the carbonate. The optimal reaction temperature and CO2 pressure established in laboratory studies are for olivine T 5 185 C and PCO2 5 15 MPa, and for heat-treated serpentine (see Table 10.6) 155 C and 11.5 MPa. In aqueous carbonation, the liquid to solid ratio (L/S) is a further optimization parameter; a lower L/S improves the heat efficiency of the process while higher L/S makes stirring and pumping easier and improves the conversion efficiency. The optimal L/S will also depend on the type of carbonation reactor, such as stirred tank or pipe configuration. Although early studies have identified serpentine as an attractive mineral feedstock for industrial-scale mineral carbonation, the layered lattice structure of the phyllosilicates, including serpentine, causes the magnesium atom to be relatively inaccessible, resulting in a slow reaction rate. A variety of pre-treatment options have been investigated with the aim of disrupting or breaking down the lattice structure to increase the reaction rate, as summarized in Table 10.6. Investigations aimed at optimizing the carbonation reaction have spawned additional basic research into the molecular-level controls on the reaction process. Examples of this work are X-ray diffraction and scanning electron microscopy studies of the dehydroxylation process in heat treatment of serpentine and of the surface morphology of mineral particles during the carbonation reaction. This is an example of the non-sequential nature of the technology development process. The latter work has led to insights into the development and exfoliation of a surface reaction “passivating” layer and the accelerating exfoliation of surface layers by the addition of abrasive, non-reactive particles such as quartz or by ultrasonic agitation, further improving the reaction rate. Any additives used would need to be efficiently recovered to avoid an economic penalty. Although heat pre-treatment of serpentine has been shown to be prohibitively energy-intensive, a possible route to mitigate this high-energy cost is through integrating mineral carbonation into a coal or biomass gasification plant. The considerable process heat from the initial partial combustion step in the gasification process would be used to heat-treat the serpentine feedstock, and CO2 produced from the WGS reaction (Section 3.1.2) would be captured in a carbonation reaction with the heat-treated serpentine. A fuller description of this process integration option is given in Section 10.5.

10.4.4 Disposal and reuse options for carbonation end products As noted above, the mineral carbonation process generates in excess of 2.5 t-reaction product per t-CO2 sequestered. For mineral carbonation to be ultimately

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Table 10.6 Mineral pre-treatment options Pre-treatment option

Description

Dry and wet grinding

Grinding to increase the specific surface area of the mineral feedstock is the first pre-treatment step. Early investigations showed that reduction of average particle size increased the extent of conversion for a given residence time in line with the increase in specific surface area. Attrition grinding, in which the mineral particles are vigorously stirred together with hard balls, can further increase reactivity by creating dislocations in the mineral lattice structure, which increases the accessibility of the metal ion. Wet attrition grinding produces smaller particles, but the equivalent dry process is more effective at disrupting the lattice structure and produces a more reactive product. Mineral feedstock is typically reduced to a mean particle diameter of less than 75 μm, a further stage reduction to less than 38 μm being a trade-off between additional energy costs (B80 kWh/t) and increased mineral conversion. Heating serpentine results in progressive removal of the hydroxyl ion (for lizardite, 45% residual OH at 580 C, 10% at 650 C) and eventually, at B1100 C, to the crystallization of forsterite and enstatite (MgSiO3). Above 580 C the dehydroxylation results in breakup of the layered serpentine structure into an amorphous phase, which exhibits a substantially increased carbonation rate compared to the untreated mineral (the higher temperature crystallized form at is less reactive). However, the energy required for pre-treatment is substantial (specific heat to 580 C plus enthalpy of dehydroxylation B330 kWh/t for lizardite feedstock) and can exceed the energy released from carbon combustion that generates the volume of CO2 captured as carbonate, resulting in a net negative sequestration efficiency! Heat treatment seems likely to be viable only when waste process heat is available through integration with another industrial process. A wide range of organic and inorganic acids, bases and salts have been investigated as options to increase feedstock reactivity, with sulfuric acid being a particularly effective agent. These treatments can increase specific surface area by a factor of 40, equivalent to reducing mean particle diameter by a factor of 6 through additional grinding. Disadvantages are the consumption of chemicals and the reduction in alkalineearth metal content of the feedstock as a result of leaching. Organic ligands have also been shown to aid the leaching of Mg. Early work on mineral activation by ultrasonic or microwave pretreatment failed to demonstrate increased reactivity; subsequently microwave heating has been shown to result in dehydroxylation of serpentine to olivine, increasing reactivity and improving grinding and slurry rheology. As noted above, exfoliation of the passivating layer by ultrasonic agitation is beneficial during the carbonation reaction.

Heat treatment

Chemical activation

Ultrasonic and microwave activation

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applied for CO2 sequestration on an impact scale, many Gt of reaction products including magnesium carbonate, silica, and other compounds will have to be dealt with annually. The eventual fate of these products, including potential reuse options, is therefore a significant issue warranting research at the technology development stage. As well as mine back-filling and land reclamation, which could consume large quantities, options that have been proposed include reuse as an additive in cement or asphalt, or for soil enhancement or ocean liming. One intriguing possibility is to follow the same route as described in Section 20.4. The carbonation reaction would be prevented from proceeding as far as the precipitation of the carbonate, and instead a solution containing the metal (Mg21) and bicarbonate (HCO32) ions plus orthosilicic acid (H4SiO4) would be discharged into the ocean. Orthosilicic acid occurs abundantly in nature and is an important nutrient for diatoms. These microscopic single-celled algae metabolize the silica from orthosilicic acid and use it to construct their cell walls. Diatoms and other phytoplankton drive the biological CO2 pump in shallow ocean waters (Section 20.2.2), fixing CO2 from surface water by photosynthesis, and ultimately contributing to the long-term carbon sink in ocean floor sediments. Diatom growth depends on the supply of nutrients, including silicon in the form of orthosilicic acid. Each spring algae bloom as surface waters warm, the bloom typically ending when the silicon supply is exhausted. Observations have shown that the bloom is extended, resulting in greater CO2 conversion into oceanic biomass, if there is a new supply of silicate from upwelling deep ocean water. Discharge of the solution containing carbonation products could therefore play a further role in CO2 sequestration by extending the annual bloom of diatomaceous algae.

10.4.5 Design and development of a demonstration-scale carbonation reactor Figure 10.10 shows a simplified process for direct aqueous carbonation of olivine. A number of different carbonation reactor designs have been proposed, including continuous-flow stirred autoclaves and pipeline reactors, although none has yet been constructed beyond a laboratory scale. A scaled-up version of the laboratory autoclave would consist of a series of stirred and heated high-pressure reactor vessels, with a total volume determined by the feedstock slurry flow rate and the residence time required to achieve the required conversion to carbonate. Figure 10.11 shows a flow-through pipeline reactor proposed by the National Energy Technology Laboratory Albany Research Center that has been successfully developed and operated at a laboratory scale in a flow-loop configuration. The reactor achieved higher carbonation conversion (Rx) than had been achieved in batch autoclave experiments. Pipe reactors offer a potential advantage of lower capital cost, although the volume requirement to achieve the required slurry throughput rate and residence time will translate into large diameter or long pipelines. As an example, a carbonation unit to sequester CO2 from a 100 MW power plant, based on wollastonite

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Olivine mine

Raw mineral

Back-fill material Solids transport to mine

Crushing and grinding

Power plant

CO2 capture and compression

Solids washing

Slurry separation

Slurry make up Carbonation reactor

CO2 off-gas recycle

H2O, NaCl

Carrier solution make up (Na2CO3 • NaHCO3 • 2H2O)

Slurry cooling

Carrier solution and solids recycle

Trona

Figure 10.10 Simplified process for direct aqueous carbonation of olivine.

Vent Gas bleed and vent CO2 feed

CO2 feed

Slurry feed

Slurry discharge and samples

Slurry pump

Figure 10.11 Proposed flow through pipe carbonation reactor.

feedstock, would require a minimum reactor volume in the region of 200 m3, equal to 1.6 km of pipe with a 40 cm internal diameter. Pipe reactors may also be less effective operationally since, in the absence of an active agitation device, slurry settling during operational shutdowns would be problematic.

10.5

Demonstration and deployment status

Impact scale deployment of mineral carbonation as a sequestration technology for carbon captured from large point sources will involve the construction and

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Table 10.7 Breakdown of estimated CO2 sequestration cost by mineral carbonation Cost element

Relative cost

Comment

Feedstock cost Electricity cost Capital cost Other costs

53% 26% 10% 11%

Wollastonite assumed in this example Of which 18% for feedstock grinding Depreciation basis Maintenance, staff, etc.

integration of a number of large-scale industrial operations. For example, sequestration of 1 Gt-CO2/year would involve: G

G

G

G

Capture of 1 Gt-CO2/year, from approximately one hundred 1 GWe coal-fired power plants (assuming 35% thermal efficiency) Transportation of captured CO2 via pipeline infrastructure to the nearest suitable mineral locations Mining of . 2 Gt/year of mineral feedstock. With a typical mine producing B100 kt/day, this would require 60 such operations to achieve the required scale Mine back-filling (100 kt/day) plus disposal of excess (50100 kt/day) carbonation products generated at each location

The cost of CO2 sequestration using a large-scale mineral carbonation infrastructure has been estimated at roughly US$120/t-CO2 avoided, which is made up as shown in Table 10.7. The best prospects for cost reduction are therefore in reducing the cost of feedstock or of energy for mineral pre-treatment. As a result, early-stage mineral carbonation demonstration projects are likely to be more closely integrated to specific industries in contrast to the more stand-alone type of operation outlined above. Possible examples are as follows: G

G

G

Steel mill with integrated mineral carbonation, eliminating feedstock cost Coal gasification power plant with integrated mineral carbonation, reducing pre-treatment energy cost Steel mill with mineral carbonation of slag by direct air capture, eliminating feedstock cost and reducing capital cost

The first two of these examples are described below, while the third is covered in Section 22.1.1.

10.5.1 Steel mill with integrated mineral carbonation There are a number of synergies that would result from the integration of mineral carbonation with steel production, including: G

G

Similar requirements for mining and pre-processing of iron ore and carbonation feedstock Potential use of peridotite (a magnesium- and iron-rich mineral—see Glossary) as a common feedstock for iron ore and magnesium silicate

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Iron ore mine Solids back-fill to mine

Crushing and grinding Fe deficient Mg silicates

CO2, acids

Carbonation plant

Silica, other by-products

Mineral separation

Magnetite

Coal

CO2 Steel mill Iron precipitate

Steel

Figure 10.12 Integrated steel mill with CO2 sequestration by mineral carbonation.

G

G

Sequestration of CO2 produced both from iron ore reduction and from the rest of the steelmaking process, totaling B1.7 t-CO2/t-steel produced Carbonation of steel slag with added value as a sellable product

Figure 10.12 shows the concept of an integrated steel mill with CO2 sequestration by mineral carbonation that has been investigated by the American Iron and Steel Institute together with Colombia University. Recent pilot-scale results on carbonation of steel slag under elevated [CO2] of 40%46% at atmospheric pressure reported CO2 uptake of B5% by weight after a 30 min reaction time in a rotating drum reactor, increasing to B10% by weight after curing for 12 days at 25 C and 100% relative humidity (Baciocchi et al., 2017). Ongoing research is aimed at optimizing operating conditions to sustain this high CO2 uptake while the slag particle size is increased to maximize its value in construction applications.

10.5.2 Coal gasification power plant with integrated mineral carbonation Gasification of hydrocarbon, coal, or biomass feedstock, described in Chapter 3, is a process that can be integrated into power generation, or the production of synthetic liquid fuels or hydrogen, with high levels of energy efficiency. The synthesis gas (syngas) produced is a mixture of carbon monoxide and hydrogen and is generated by combustion of the feedstock in an oxygen-poor environment, leading to partial oxidation. Depending on the application, some or all of the carbon monoxide in the syngas can be converted to CO2 using a WGS reaction, typically carried out at a temperature of 300500 C: CO 1 H2 O ! CO2 1 H2

(10.31)

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279

Steam N2 Air

Coal

Liquid fuel Air separation

Fischer–Tropsch Plant

O2 Gasification

H2 Cooling

WG Shift

Cleanup

Heat integration

Olivine H2O, NaCl Trona

Crushing and grinding

Heat pre-treatment

Capture

Sulfur CO2

Carrier solution makeup

Slurry makeup

Carbonation reactor

Solids washing

Slurry separation

Slurry cooling

(Na2CO3•NaHCO3•2H2O) Back-fill material

Figure 10.13 Coal gasification, liquid fuel synthesis plant with integrated mineral carbonation.

For example, if the syngas is to be used for liquid fuel synthesis using the FischerTropsch process, B35% of the syngas needs to be shifted in order to achieve the required CO to H2 ratio. For a typical syngas composition this results in a post-WGS syngas containing B60% CO2 by weight. Syngas leaves the partial oxidation step at a temperature of B1500 C, and the heat available in cooling the gas to the desired temperate for the WGS reaction (B1.47 MJ/kg-syngas) can be used for heat pre-treatment of serpentine to create a more active feedstock for carbonation. Each kilogram of syngas cooled can heatactivate B1.1 kg-serpentine (1.32 MJ/kg) and yields 0.75 kg-CO2 if 35% of the CO is water-shifted. Since the RCO2 of heat-activated serpentine is 2.1 kg/kg-CO2, 0.52 kg-CO2 can be sequestered via carbonation, which is 70% of the CO2 generated in the shift reaction. Figure 10.13 shows a schematic diagram of a coal gasification, liquid fuel synthesis plant with integrated CO2 sequestration by mineral carbonation. Additional process heat integration is shown, with the cooled syngas exiting the gasification reactor being used to pre-heat the incoming crushed and coarsely ground serpentine feedstock. Fine grinding of the mineral is not required because larger particles, up to a few millimeters, will fragment due to the expansion of steam released during dehydroxylation.

10.5.3 In situ carbonation In situ carbonation in flood basalt: the Wallula basalt injection pilot The potential for carbon storage in continental flood basalts was pointed out by McGrail et al. (2006), and a pilot CCS project—the Wallula Basalt

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Sequestration Pilot Project—was planned by this group as part of the US Department of Energy’s Big Sky Regional Carbon Sequestration Partnership. The initial pilot scope included capture of up to 0.8 Mt-CO2/year from the power island of the Boise White Paper mill, located on the banks of the Columbia River in Washington state, and injection of scCO2 into permeable flow units in the Columbia River Basalt Group which underlies .200,000 km2 of Washington, Oregon, and Idaho. Following site assessment using 2D seismic data, a pilot well was drilled in 2009 for site characterization and identified a suitable injection zone at B850 m depth, with 28 m net thickness and an average permeability of 4490 mD estimated from constant-rate pumping tests. Injection tests also confirmed the presence of three intervals that would act as flow barriers above the injection zone, with permeabilities of 0.010.1 μD. Unfortunately the integrated CCS pilot was shelved in 2011 when DOE funding was not secured for the next phase. Funds were however available for an injection pilot and, in 2013, 977 t-CO2 was injected over 25 days in the world’s first scCO2 injection test into flood basalt. Post-injection fluid sampling showed 100- to 1000-fold increase in Ca, Mg, Fe, and Mn cation concentrations compared to pre-injection samples, as well as 13C and 18O isotopic shifts consistent with the onset of geochemical reactions. Geochemical analysis of sidewall core samples recovered prior to well abandonment in 2015 confirmed the rapid conversion of injected scCO2 to carbonate minerals, which were visible as nodules of ankerite (Ca(Fe,Mg,Mn)(CO3)2) distributed within the basalt matrix (McGrail et al., 2017).

In situ carbonation in mid-ocean ridge basalt: the CarbFix project Alongside continental flood basalts, mid-ocean ridges and submarine flood basalts also have the potential for impact scale carbon storage, with a potential global capacity estimated at 100,000250,000 Gt-CO2, and the CarbFix pilot project aims to test this concept in southwest Iceland. This project takes a different approach from Wallula, where scCO2 is injected. Instead, gaseous CO2 and water are separately injected into the test well and are mixed at 350 m, at a hydrostatic pressure of 2.5 MPa. Small gas bubbles are entrained in the descending water stream and are full dissolved at the injection depth of B2000 m. Groundwater, available in plentiful supply, will be used for the pilot and 22 kgwater is required to fully dissolve each kg-CO2 at the operating pressure and temperature. Seawater could also be used but the required volume would increase to 31 kg/kg-CO2. Brine pH at the injection point will be B3.7 and, as can be seen from Figure 10.2, the B1 mol/kg total dissolved inorganic carbon will be almost entirely H2CO3 . Injection into a porous basalt body of roughly 1 km3 (2 km 3 1 km 3 500 m thick), which is estimated can store 12 Mt-CO2 on the basis of 10% of the pore space (B1% of the gross rock volume) being ultimately filled by calcite precipitate.

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An initial pilot project from 2010 to 2012, captured 2.2 kt-CO2/year in a slipstream from the 213 MWe Hellisheidi geothermal power plant, and ramp-up toward full capture and injection of the 60 kt-CO2/year emitted by the plant began in 2014. Sub-surface monitoring has been accomplished using both conservative and reactive tracers, fluid sampling and wireline coring in a number of monitoring wells has shown rapid mineralization of the dissolved CO2. Modeling of tracer breakthrough results indicate mineralization of .80% of injected CO2 within 12 months and .95% within 24 months of injection.

10.6

References and resources

10.6.1 References Baciocchi, R., Costa, G., Librandi, P., Stendardo, S., Bello de Souza, A.C., Luna, A.S., 2017. Carbonation of steel slags: testing of the wet route in a pilot-scale reactor. Energy Procedia. 114, 53815392. Bobicki, E., Liu, Q., Xu, Z., Zeng, H., 2012. Carbon capture and storage using alkaline industrial wastes. Prog. Energy Combust. Sci. 38, 302320. Gerdemann, S.J., O’Connor, W.K., Dahlin, D.C., Penner, L.R., Rush, H., 2007. Ex situ aqueous mineral carbonation. Environ. Sci. Technol. 41, 25872593. Gislason, S., et al., 2010. Mineral sequestration of carbon dioxide in basalt: a pre-injection overview of the CarbFix project. Int. J. Greenhouse Gas Control. 4, 537545. Goldberg, D., Slagle, A., 2009. A global assessment of deep-sea basalt sites for carbon sequestration. Energy Procedia. 1, 36753682. Huijgen, W.J.J., Comans, R.N.J., Witkamp, G.-J., 2007. Cost evaluation of CO2 sequestration by aqueous mineral carbonation. Energy Convers. Manage. 48, 19231935. IEA Greenhouse Gas Programme, 2005. Carbon dioxide storage by mineral carbonation. IEA Greenhouse Gas Programme Report 2005/11. IPCC, 2005. Special Report on Carbon Dioxide Capture and Storage, Chapter 7Mineral Carbonation and Industrial Uses of Carbon Dioxide. Cambridge University Press, Cambridge, UK. Kamennaya, N.A., Ajo-Franklin, C.M., Northen, T., Jansson, C., 2012. Cyanobacteria as biocatalysts for carbonate mineralization. Minerals. 2012 (2), 338364. Lackner, K.S., et al., 1995. Carbon dioxide disposal in carbonate minerals. Energy. 20, 11531170. Lee, S.W., Park, S.B., Jeong, S.K., Lim, K.S., Lee, S.H, Trachtenberg, M.C., 2010. On carbon dioxide storage based on biomineralization strategies. Micron. 41 (4), 273282. Ma, J., Yoon, R.-H., 2015. CO2 mineralization in artificial seawater, Chapter 12. In: Morreale, B., Shi, F. (Eds.), Novel Materials for Carbon Dioxide Mitigation Technology. Elsevier, Amsterdam, Netherlands. McGrail, B.P., et al., 2006. Potential for carbon dioxide sequestration in flood basalts. J. Geophys. Res. 111. McGrail, B.P., Cliff, J.B., Qafoku, O., Thompson, C.J., Sullivan, E.C., 2017. Wallula basalt pilot demonstration project: post-injection results and conclusions. Energy Procedia. 114, 57835790. Power, I., et al., 2013. Carbon mineralization: from natural analogues to engineered systems. Rev. Mineral. Geochem. 77, 305360.

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Ragnheidardottir, E., Sigurdardottir, H., Kristjansdottir, H., Harvey, W., 2011. Opportunities and challenges for CarbFix: an evaluation of capacities and costs for the pilot scale mineralization sequestration project at Hellisheidi, Iceland and beyond. Int. J. Greenhouse Gas Control. 5, 10651072. Seifritz, W., 1990. CO2 disposal by means of silicates. Nature. 345, 486. Slotte, M., Roma˜o, I., Zevenhoven, R., 2013. Integration of a pilot-scale serpentinite carbonation process with an industrial lime kiln. Energy. 62, 142149. Stolaroff, J.K., Lowry, G.V., Keith, D.W., 2005. Using CaO- and MgO-rich industrial waste streams for carbon sequestration. Energy Convers. Manage. 46, 687699. Wang, W., M. Hu, C. Ma, 2010. Possibility for CO2 sequestration using sea water. In: 4th International Conference on Bioinformatics and Biomedical Engineering (iCBBE). IEEE. Zevenhoven, R., et al., 2013. Carbon storage by mineralisation (CSM): serpentinite rock carbonation via Mg(OH)2 reaction intermediate without CO2 pre-separation. Energy Procedia. 37, 59455954. Zhang, X., Yan, S.Y., Tyagi, R.D., Surampalli, R.Y., Zhang, T.C., 2015. Enzymatic sequestration of carbon dioxide. In: Surampalli, R.Y., et al., (Eds.), Carbon Capture and Storage: Physical, Chemical, and Biological Methods. American Society of Civil Engineers, Reston, VA.

10.6.2 Resources ˚ bo A

Akademi University, Finland: http://web.abo.fi/fak/tkf/vt/Eng/research_Carbon DioxineCapture.htm. BioMASON (using MICCP technology to “grow” construction materials): www.biomason. com. Calera Corp. (biomimetic carbon mineralization for commercial products): www.calera.com. CarbFix project: www.or.is/english/carbfix-project/about-carbfix. Energy Research Centre of the Netherlands (ECN): www.ecn.nl. Mineral Carbonation International (MCi) (Australian company developing technology carbon capture and use through mineral carbonation): www.mineralcarbonation.com. Oman Drilling Project (drilling, coring, fluid sampling and evaluation project to investigate ophiolite formation and alteration including weathering processes that lead to natural uptake of CO2): www.omandrilling.ac.uk. University of British Colombia, Department of Earth and Ocean Sciences (EOS): www.eoas. ubc.ca/research/areas. Wallula Basalt Pilot Project: www.bigskyco2.org/research/geologic/basaltproject.

Introduction to geological storage

11

In contrast to the wide range of technologies that have been developed, demonstrated, and in many cases deployed, for capturing CO2, injection into permeable subsurface rock formations—geological storage—is the only storage technology that has yet been demonstrated and deployed on a commercial scale. Many technologies and methodologies that have been developed in the oil and gas industry are applicable with minor modification to the challenges of geological storage, from the selection of suitable storage sites to the monitoring of CO2 plume movement, and this has undoubtedly contributed to the rapid implementation of early storage projects. Geological storage was first proposed in the 1990s as the final step in the CCS process (see Koide et al., 1992). Koide and co-workers recognized that “useless” saline aquifers were globally much more widely distributed than depleted oil or gas fields where CO2 injection, particularly to enhance oil recovery (EOR), had been practiced since the 1970s. Although injection into saline aquifers and oil reservoirs for EOR are still considered the main contenders for large-scale storage, considerable attention has also been given in recent years to a growing range of alternative options, as summarized in Table 11.1. All storage options that involve CO2 injection into porous and permeable sedimentary rocks (i.e., all but ECBM and in situ mineral carbonation) rely on the same physical and chemical mechanisms to trap and progressively immobilize CO2 within the storage formation. These mechanisms are introduced below and are discussed in detail in Chapters 12 to 16. Saline aquifer storage is then discussed from a project perspective in Chapter 17, while the other subsurface storage options are discussed in Chapter 18. Concluding Part III, site characterization and the monitoring of CO2 storage are discussed in Chapter 19.

11.1

CO2 trapping mechanisms

Storage of CO2 in a subsurface host formation is achieved through the pumping of CO2 into injection wells that are drilled and completed in the selected formation. Both the capacity of a storage site and the security of containment are maximized if CO2 is injected into the subsurface as a supercritical fluid, since in this state it has a liquid like density and a significantly lower mobility through the pore space than

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00011-8 © 2017 Elsevier Inc. All rights reserved.

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Table 11.1 Subsurface carbon storage options Subsurface storage option

Description

Saline aquifer storage

Injection into saline aquifers that are not considered potential drinking water resources Injection into operating oil fields, typically those containing heavier oil, initially to maximize economic oil recovery and more recently to also achieve CO2 storage Similar to EOR, injection into depleted or operating gas fields with the objective of co-optimizing hydrocarbon recovery and CO2 storage Injection into unmineable coal seams, increasing CBM recovery by preferential adsorption of CO2 and desorption of methane Use of CO2 as a working fluid in geothermal energy extraction and storage systems, a variant being the extraction of heat from an injected CO2 plume in a saline aquifer (CO2 plume geothermal) Use of CO2 as a cushion gas to store energy from intermittent sources such as wind or solar power systems Injection of CO2 into fractured alkali mineral deposits, such as sheet basalts, and storage via mineral carbonation

Enhanced oil recovery (EOR)

Enhanced gas recovery (EGR)

Enhanced coal bed methane recovery (ECBM) Enhanced geothermal systems (EGS)

Compressed air energy storage systems (CAES) In situ mineral carbonation

it would have as a gas. This necessitates injection at a depth where the hydrostatic pressure exceeds the critical pressure (Pc 5 7.38 MPa), which is typically reached at around 800 m (the critical pressure depth). In the following discussion, all references to injected CO2 refer to a supercritical fluid (scCO2) unless otherwise stated. One injected into the formation, the fluid will move under the influence of viscous, capillary, and gravity forces, its ultimate fate being determined by a number of trapping mechanisms upon which the storage capacity of the complex depends. For each trapping mechanism, the theoretical storage capacity is indicated. This theoretical capacity represents the physical limit of storage volume that could be achieved assuming that the entire pore space is accessible and utilized. The classification of more practical capacities, derived by applying technical, regulatory, and commercial constraints to this theoretical maximum, is described in Section 11.2.

11.1.1 Structural and stratigraphic trapping The buoyancy of injected CO2 relative to the in situ pore fluid will result in its upward migration until an impermeable barrier or caprock is encountered. The storage

Introduction to geological storage

287

Figure 11.1 Structural and stratigraphic trap configurations: (A) Anticline, (B) sealing fault, (C) stratigraphic pinchout, and (D) unconformity.

formation, together with all formations that prevent upward or lateral migration are collectively termed the storage complex or storage assessment unit (SAU). Subsequently, CO2 may migrate laterally under buoyant (i.e., gravity) or hydrodynamic forces, or it may “pond” beneath the caprock, if the geometry or other lateral changes in permeability prevent further migration. Since this trapping mechanism is directly related to the buoyancy of CO2 relative to water, the term buoyant trapping is often used as an alternative to structural or stratigraphic trapping. Structural and stratigraphic traps, also known as static traps, are familiar from oil and gas field practice, and a range of trap types is illustrated in Figure 11.1. As migration of CO2 continues, the trap will fill and the lower limit of the ponded CO2 (the CO2
water contact (CWC) in an aquifer) will become deeper until: G

G

G

the CWC drops to the spill point of the structure—the point where the structural or stratigraphic element causing the trap is on longer present, as indicated in Figure 11.1A. Further migration into the trap will cause CO2 to spill out at this point and migrate beyond the trap. the height of the trapped CO2 column grows to the point where the CO2 pressure at the crest of the structure exceeds the capillary entry pressure of the caprock (see Chapter 13), at which point CO2 will start to leak into and possibly through the caprock. the pore pressure within the structure exceeds the fracture initiation pressure in the caprock (see Chapter 12), or the reactivation pressure of any fault or fracture crossing the storage complex, at which point CO2 may start to leak out of the storage complex.

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The theoretical storage capacity is defined as the physical limit of storage volume or mass that can be accepted by a geological system, assuming the entire pore space is filled and excluding any technical, engineering, or other constraints. When expressed as a mass of CO2, the theoretical capacity of a structural or stratigraphic trap is given by: mCO2 t 5 AhΦð1 2 Swirr ÞρCO2

(11.1)

where A, h, and Φ are the area, average thickness, and volume averaged effective porosity of the trap, Swirr is the average irreducible water saturation within the trap pore volume, and ρCO2 is the average density of CO2 in the trap at in situ conditions of temperature and pressure. The effective porosity excludes any disconnected porosity such as vugs in carbonate rocks and clay-bound water in shaly sandstones. The time scale of structural trapping is determined by the time for CO2 to migrate into the trap from the point of injection, and will typically occur in a few decades, after which the trapped CO2 will more gradually disperse as a result of dissolution and gravity currents or geochemical reactions with the storage formation or caprock. Equation (11.1) assumes that the storage formation is open, for example, a deep saline aquifer at hydrostatic pressure that has a remote connection to the surface, and the increase in pore pressure of the system as a result of injection is not considered when estimating theoretical capacity. However, if injection is into a closed system then the increase in overall pore pressure must be considered in determining theoretical capacity. In this case the theoretical storage capacity will be given by: mCO2 t 5 Vtrap κt ΔPmax ρCO2

(11.2)

where Vtrap is the total pore volume of the closed storage complex, κt is the total system compressibility—a combination of rock and fluid compressibility (κt 5 κr 1 κf), and ΔPmax is the maximum increase in pressure that can be sustained without leakage, for example, as a result of mechanical failure of the caprock or the reactivation of existing faults or fractures (see Chapter 12). The pore pressure increase in a closed system can be relieved by pumping-off water, in which case the additional term WpρCO2 would be added to the RHS of Equation (11.2), where Wp is the volume at downhole conditions of the produced water. This and other reservoir management techniques for saline aquifer storage are discussed in Chapter 17. Compared to the other trapping mechanisms described below, the risk of leakage is highest for CO2 that is structurally trapped, as the fluid remains mobile and can migrate through the caprock if this is compromised by faults, fractures or permeable paths along wells, or fails at some point due to geochemical or geomechanical processes. Static trapping can also occur under smaller trapping elements, such as irregularities in a dipping planar caprock surface or small-scale impermeable layers within the storage formation. Capillary trapping is a related mechanism and occurs when

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capillary forces immobilize lenses of CO2 below small scale, low permeability layers, as illustrated in Figure 11.2. Any estimate of the storage capacity of such small-scale structural and stratigraphic elements will be extremely uncertain, even after detailed geological site assessment, since they are far below the resolution of the available surveying technologies. High-resolution 4D seismic monitoring after a period of injection will be the most likely tool to provide insight into these mechanisms. Storage can also take place in an open system where there is a continuous permeable connection to the surface, for example, below a gently dipping caprock as shown in Figure 11.3, provided that the time scale for buoyant migration to the critical pressure depth is longer than the time scale for dissolution. This situation, known as hydrodynamic trapping, can occur under a caprock of very low dip angle or under a more moderate dip if the buoyant migration is hindered by a countercurrent hydrodynamic flow (see Chapter 15).

Caprock mineral grain Narrow pore throats in caprock or low permeability layer prevent CO2 entry Aquifer mineral grain Brine filled pore space Capillary trapped CO2

Figure 11.2 Capillary trapping mechanism.

Distant aquifer outcrop Impermeable rock Caprock Slowed or arrested migration

CO2 plume

w

nal flo

Regio

Brine filled aquifer Permeable Impermeable

Figure 11.3 Hydrodynamic trapping—very slow movement in an open monocline.

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11.1.2 Residual trapping As a plume of buoyant CO2 rises through a water-saturated formation, the CO2 will initially expel water from the pore space and then, in the wake of the rising plume, water will again be drawn into the pores by capillary imbibition. As described in Chapter 13, as the saturation of a mobile phase reduces, the permeability of the rock to that phase also declines, approaching zero at the residual saturation. At the plume front, this process reduces the water saturation to a residual water saturation (Swrc)—and later, in the wake of the plume, the CO2 saturation will similarly be reduced to a residual value (Scrw). Here the suffix irj indicates that phase i is at residual saturation due to displacement by phase j. In this case the whole rock volume swept out by the rising plume will retain a residual CO2 saturation. Figure 11.4 illustrates this process on a pore scale. The theoretical storage capacity for residual trapping can be estimated from: mCO2 t 5 AhΦScrw ρCO2

(11.3)

with terms as defined above. This estimate of theoretical capacity assumes that injected CO2 invades all of the effective pore space throughout the storage formation, a situation which could only be approached by applying various reservoir management techniques to maximize the gross rock volume swept by the CO2 plume (see Chapter 17). Residual trapped CO2 has a very low risk of leakage since the relative permeability of the residual phase is essentially zero. Over time, the residually trapped CO2 will dissolves in the formation brine and mix with the surrounding unsaturated aquifer water.

Wide pore throats allow water imbibition Mineral grain Brine filled pore space Residual CO2 Narrow pore throats create pore scale capillary traps

Figure 11.4 Residual trapping of CO2 following plume migration through an aquifer.

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11.1.3 Solubility trapping Dissolution of CO2 and convective mixing into the formation brine is the major long-term trapping mechanism in a saline aquifer. The solubility of CO2 depends on temperature, pressure, and on the geochemical composition of the formation brine and is further discussed in Chapter 13. The theoretical storage capacity for solubility trapping can be estimated from the formula: mCO2 t 5 AhΦðρbS XS CO2
ρb0 X0 CO2 Þ

(11.4)

where ρb is the brine density, XCO2 the mass fraction of CO2 dissolved in the brine, subscripts 0 and S indicate initial and CO2 saturated conditions, and other terms are as previously defined. Solubility trapping presents a very low leakage risk, as the dissolved CO2 will only come out of solution if there is a significant reduction in pressure, for example, as a result of updip migration of saturated brine over long distances or leakage into a shallower formation. Dissolution is effective on a centennial time scale, but can be considerably accelerated by applying specially designed injection strategies, as described in Chapter 17, or if the aquifer is hydrodynamically active. Depending on the brine composition, pH, and the mineralogy of the storage complex, solubility trapping may be enhanced by the formation of bicarbonate or carbonate ions and other ionic complexes, resulting in additional ionic trapping.

11.1.4 Ionic trapping As described in Section 10.1, once CO2 has dissolved in formation brine to form carbonic acid (H2CO3), successive deprotonations produce first the bicarbonate ion 22 (HCO2 3 ) and then the carbonate ion (CO3 ), according to Reactions (10.3) and (10.4). As shown in Figure 10.2, for pH above pKa1 (B6.3), carbon will be predominantly in the form of the bicarbonate or, above pKa2 (B10.3), the carbonate ion. Ionic trapping therefore occurs for pH greater than B6, when the majority of the dissolved carbon is in an ionic state rather than as carbonic acid and aqueous CO2. Figure 11.5 illustrates this pH dependence of solubility versus ionic trapping and also shows that solubility and ionic trapping give way to mineral trapping—the most stable of the trapping mechanisms—with increased availability of Ca, Fe, or Mg cations.

11.1.5 Mineral trapping By analogy with mineral carbonation, discussed in the previous chapter, the reaction of dissolved CO2 with Ca, Fe, or Mg containing minerals in the rock matrix can result in the precipitation of carbonates in the pore space. This is the slowest

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log [Ca2+, Mg2+, Fe2+]

Mineral trapping (CaCO3, MgCO3, FeCO3)

Solubility trapping (CO2(aq) + H2CO3)

2

4

Ionic trapping (HCO3–)

6

8

Ionic trapping (CO32–)

10

12

14 pH

Figure 11.5 Trapping dependence on formation water pH and cation concentration. Source: After Gunter et al. (2004).

potential trapping process, operating on a millennial time scale under subsurface conditions, but is the one process that leaves CO2 in a completely immobile state. Geochemical reactions need not be confined to the storage formation and may also occur when CO2 contacts the caprock above the injection formation. For example, geochemical analysis for the Sleipner project indicated that silicates present in the Utsira caprock would react with formation brine and CO2 to form carbonates. In this case the resulting increase in mineral bulk volume reduces porosity and permeability and leads to enhanced caprock integrity over time. The theoretical storage capacity for mineral trapping is given by: mCO2 t 5 AhΣi ci χiCO2 MCO2 =Mi

(11.5)

where ci is the concentration of mineral i in the storage formation (kg m23), χiCO2 is the stoichiometric fraction of CO2 consumed in the carbonation reaction (mol-CO2/ mol-mineral i), and MCO2/Mi is the ratio of the molecular weights. This theoretical capacity assumes that dissolved CO2 contacts all of the reactive minerals in the formation and remains in contact long enough for complete carbonation to occur.

11.1.6 Indicative specific capacities of saline aquifer trapping mechanisms Table 11.2 gives an indication of the specific capacities of these trapping mechanisms, expressed in kg-CO2/m3 of storage formation volume, as well as the time scale for trapping to occur.

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Table 11.2 Indicative specific capacities of saline aquifer trapping mechanisms Trapping mechanism

Indicative specific capacity (kg-CO2/m3)

Effective time scale (years)

Structural trapping Residual trapping Solubility trapping Ionic trapping Mineral trapping

50
200 10
50 1
20 1
20 1
100

10 to 1000 10 to 1000 100 to .1000 100 to .1000 1000 to .10,000

Structural trap volume Residual trap volume Spill points

Solubility trap volume Caprock

Microscale structural traps

Brine filled aquifer lt to

Fau e

fac

sur

Impermeable rock

Figure 11.6 Storage volumes applicable to different trapping mechanisms.

The relevant formation volume to which these specific capacities would be applied differs for each trapping mechanism, as shown in Figure 11.6. For structural trapping this is the total volume beneath all structural trapping elements accessed by migrating CO2, on all distance scales, limited either by the individual spill points or by the maximum buoyant column height that can be sustained given the geomechanical constraints. For residual trapping the relevant volume is the total gross rock volume swept out by migrating CO2, while for solubility, ionic and mineral trapping the latter volume plus the additional rock volume swept out by gravity currents or hydrodynamic flows of CO2 saturated brine will apply. Consequently, with the exception of structural trapping, storage capacity will be increased by any feature or process that tends to increase the gross rock volume swept by the migrating plume. Examples of such features and processes, discussed further in the relevant sections below, include: G

G

G

G

G

Low vertical permeability Heterogeneous geological features that impede vertical flow Injection of water, concurrently or following CO2 injection An active hydrodynamic regime Higher operating pressures in injection wells

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11.1.7 Time dependence of saline aquifer trapping mechanisms The trapping mechanisms described above operate on widely different time scales, as noted in Table 11.2 and illustrated in Figure 11.7. Structural and residual trapping are the most important mechanisms on an operational time scale (decades), while solubility and mineral trapping largely determine the long-term fate of injected CO2 (centuries to millennia). Because of the slower time scales, solubility and mineral trapping are often excluded in high-level (regional, national, etc.) estimates of storage capacity on the basis that they contribute at best a few extra percent over a realistic storage injection period.

11.2

Storage capacity classification and estimation

Trapping mechanism contribution (%)

Koide and co-workers estimated a global capacity for geological storage in saline aquifers of 320 Gt-CO2 (87 Gt-C), on the assumption that 1% of the total area of all sedimentary basins would be utilized and that capacity would be determined by CO2 solubility. More recent estimates suggest that this figure could be exceeded by a factor of 10 for the USA alone, and that global storage capacity in saline aquifers could reach 20,000 Gt-CO2. Geological storage capacity may be assessed on many scales, from country to basin or down to a specific site, and a wide range of assumptions and boundary conditions may be applied in individual estimates. Irrespective of the geographical scale of an estimate, consistency of definitions is essential to allow meaningful aggregation, and this begins with the classification of storage resource estimates.

100 Structural, stratigraphic, and hydrodynamic trapping

Residual trapping

50 Increasing security of storage

Solubility and ionic trapping Mineral trapping

0 1

10

100

1000

Time from start of injection (Years)

Figure 11.7 Relative importance of trapping mechanisms through time.

10,000

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11.2.1 Classification of storage capacity estimates The classification system developed by the Carbon Sequestration Leadership Forum (CSLF), summarized in Table 11.3, provides a convenient starting point for discussing the factors that determine storage capacity and has been widely used in many assessments. This system is known as the Techno-Economic Resource-Reserve Pyramid for CO2 Storage Capacity, and illustrated by the structure shown in Figure 11.8, in which the theoretical capacity occupies the whole volume of the pyramid, while the progressively constrained volumes occupy reducing fractions of the total. The committed storage capacity is an addition to the CSLF scheme by analogy with the concept of committing hydrocarbon gas to long-term supply contracts and will be relevant when geological storage is offered as a utility.

Table 11.3 Classification scheme for GCS capacity Storage category

Description

Theoretical storage capacity

The physical limit of storage volume in a geological system, assuming the entire pore space is accessible and utilized and that adsorption (where relevant) reaches 100% saturation within the entire volume Derived from the theoretical storage capacity by applying appropriate geological and engineering cut-offs; dependent on site-specific or regional data, and time dependent as performance data and experience are acquired and new technologies become available Viable capacity is derived from the effective capacity by considering non-technical factors, e.g., economic or regulatory limits; also a time dependency on economic and regulatory developments Derived by matching the viable capacity with available sources that meet the technical requirements of a storage site, such as ability to deliver a specific supply rate. The difference between matched and viable capacity is termed stranded capacity, since it cannot be utilized due to a lack of sufficient economically viable or technically suitable producers The committed capacity is that part of the matched capacity that has been contracted to specific producers. The difference between matched and committed capacity is therefore available to be contracted to new producers or to the extension of existing supply contracts

Effective (or realistic) storage capacity

Viable (or practical) storage capacity

Matched storage capacity

Committed storage capacity

Source: After CSLF (Carbon Sequestration Leadership Forum), 2007.

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Increasing certainty of storage potential

Committed capacity

Increasing cost of storage

Matched capacity

Practical capacity

Effective capacity

Theoretical capacity

Figure 11.8 Techno-economic resource-reserve pyramid. Source: After CSLF (Carbon Sequestration Leadership Forum), 2007.

This techno-economic framework is one of a number of classification schemes that have been applied by various bodies to estimate storage resources. International efforts to achieve consistent resource estimates (see, e.g., Frailey, 2017) are increasingly focusing on estimation of the total accessible storage resource (TASR), defined as the mass of CO2 that may be injected and stored using current geologic and hydrologic knowledge of the subsurface and all currently available technologies and engineering practices. Within the CSLF framework this is most closely related to the effective capacity, with some differences noted below.

11.2.2 Limitations on effective storage capacity The ratio of effective to theoretical storage capacity is known as the storage efficiency, and results from the application of subsurface technical and engineering cut-offs, such as a geomechanical limit on well injection pressure or pore pressure increase. Some of the factors that determine effective storage capacity in relation to specific trapping mechanisms are summarized in Table 11.4 and the following sections and are described in detail in the following chapters. The cumulative volumetric effect of all factors is captured in the storage efficiency factor which represents the fraction of the total available pore space that will be occupied by CO2. Storage efficiencies refer to specific trapping mechanisms and are designated BSE for structural/buoyant, and RSE for residual trapping. These factors address CO2 present as a free phase within the pore space; solubility/ionic and mineral trapping are typically excluded from high level storage capacity estimates since at best they represent only a small additional percentage during the time scale for storage operations. Various engineering approaches have however been proposed to accelerate CO2 dissolution which could substantially increase its contribution on an operational time scale (see Chapter 17). A full evaluation of these

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Table 11.4 Factors that determine effective geological storage capacity Limiting factor

Applicable trapping mechanisms

Description

Geomechanical

Structural and residual trapping

Fluid flow

Residual trapping

Rock
fluid interactions

Residual trapping

Maximum pressure increase that can be sustained without geomechanical failure of the storage formation or caprock Residual trapping can only occur within the gross volume swept by the migrating plume, which is controlled by factors such as vertical permeability and reservoir heterogeneity The residual saturation of CO2 will be influenced by the maximum achievable injection rate The maximum column height in a structural trap may be limited by the capillary entry pressure of CO2 into the caprock The pore space occupied by irreducible formation brine becomes available for structural trapping on a timescale reflecting its rate of dissolution into trapped CO2 Maximum pressure increase or plume extent that can be sustained without adverse impact on potable water resources Potential for pressure management techniques to mitigate pore pressure increase and remove or relax the geomechanical limit Regulatory requirements in a specific jurisdiction may further limit the extent to which the technical storage capacity can be effectively utilized

Structural trapping

Fluid
fluid interactions

Structural trapping

Hydrological

Structural and residual trapping

Operational— pressure management

Structural and residual trapping

Policy constraints

All

trapping processes is therefore essential for project-specific storage assessment and for evaluating the long-term fate of stored CO2 and will also influence post-closure monitoring. In an estimation of TASR rather than effective capacity, the last three factors in Table 11.4 would likely be treated as defining contingent subsets of the total storage resource, since the definition of protected water resources, the permissibility or otherwise of pressure management techniques and any other policy constraints will apply only in specific jurisdictions and are not therefore purely technical in nature.

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11.2.3 Probabilistic storage capacity estimation It is clear from Table 11.4, and will be emphasized through the following chapters, that any storage capacity estimate is dependent on a wide range of factors, some of which may be determined with reasonable precision (e.g., ρCO2), others with at least some degree of certainty (e.g., Swirr, Scrw) while others, such as the spatial and size distribution of small-scale trapping heterogeneities, will be very poorly determined. Probabilistic estimation techniques can be used to ensure that these uncertainties are reflected in a storage capacity estimate. This practice is enshrined in the oil and gas industry’s use of proved, probable, and possible reserves, which reflect high, moderate, and lower levels of certainty that a resource volume will be economically producible. In similar vein, decision makers—at all levels from individual project up to international policy—will need to understand the range of possible outcomes in order to make good quality decisions. The probabilistic estimation method is illustrated in Figure 11.9. First, reference or “mid” case maps and estimates are made for each parameter in the capacity equation. Depending on data availability, mapping may be limited to a structural depth map to estimate applicable gross rock volume or, if there is sufficient well data, thickness, porosity, and permeability maps may also be generated. The range of uncertainty is then assessed for each input parameter and represented as a probability density function (pdf). Common examples are a triangular distribution specified by a minimum possible, most likely, and maximum possible value, or a normal or log normal distribution specified by a mean and standard deviation. For mapped inputs, low and high case maps would be generated to determine the pdf end points. Finally, these parameter uncertainty distributions are sampled using a Monte Carlo technique to generate many thousands of capacity estimates which are displayed as a density function or cumulative probability curve.

Prob. density

Mid

P(90)

P(50)

Max

Min

Mid

Max

Cumulative prob.

Monte Carlo sampling to generate storage volume pdf and cum. probability curve

Min Prob. density

Assess range of uncertainty for each input parameter, and represent as a pdf

Prob. density

Generate reference case structure and property maps

P(10) Volume

Figure 11.9 Probabilistic storage capacity estimation methodology.

P(90)

P(50)

P(10) Volume

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From these curves, the storage capacity at any confidence level can be determined. For example, a high confidence value such as a P(90) estimate—for which there is a 90% probability that actual capacity will exceed the estimate—may be used by a storage operator when committing volume to a CO2 supplier such as a power plant operator. Sensitivity analysis, identifying which input parameters have the greatest impact on capacity uncertainty, may be used to define a data gathering or monitoring program that can have the greatest impact in narrowing the uncertainty range, potentially leading to larger committable volumes.

11.3

Features, events, and processes in geological storage

The application of systems analysis techniques to the subsurface was pioneered by Sandia National Laboratories, Albuquerque, NM during the 1980s for the assessment of geological sites for nuclear waste disposal. The tools developed included the cataloguing of features, events, and processes (FEPs) relevant to the containment system, the use of interaction matrices to identify and rank interactions and the development and ranking of scenarios as the basis for the assessment of possible future states of the system. These tools have been widely applied in recent years in assessing the performance and safety of geological storage, and several examples of the FEP analysis in practice, as well as comparative reviews of other assessment approaches, are included in the list of references.

11.3.1 Introduction to the FEP approach The first step in the analysis of a specified system is the identification of FEPs that could directly or indirectly influence the current or future states of the system. FEPs are defined as: Features: physical, chemical, or biological properties or characteristics of the system, for example, the chemical composition of an aquifer brine, or the density and orientation of a fracture network within a geological formation. Events: discrete changes in the system that occur over short or very short time scales, such as the drilling of a new well or the initiation of a fracture. Processes: changes in the evolution of the system that occur over longer timescales, such as the injection of CO2 into the storage reservoir, the movement, dissolution, etc., of injected fluids.

FEPs of importance for geological storage span very wide scale ranges in both space and time. This is illustrated in Figures 11.10 and 11.11, where the characteristic distance and time scales of some important geological storage FEP are shown to span 9 orders of magnitude in space (0.1 mm to .100 km) and 7 orders of magnitude in time (from minutes to millennia). The consequence of this broad span is that any model built to assess aspects of geological storage can only incorporate a subset of relevant FEPs—those with the greatest influence on the question being addressed by the modeling effort—and must necessarily make approximating assumptions in relation to others.

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Nano

Micro

Meso

Macro

Aquifer extent Pressure perturbation Final plume radius Inter-well spacing Formation thickness Capillary transition Wellbore flow Fracture width

Fluid interfaces 1 mm

10 cm

10 m

1 km

100 km

Characteristic distance scale

Figure 11.10 Characteristic distance scales of different features and processes. Source: After Celia and Nordbotten (2011).

Nano

Micro

Meso

Macro

Mega

Mineral reactions Diffusive leakage Convective mixing Plume migration Injection period Gravity segregation Wellbore leakage Capillary equilibrium Phase equilibrium 0.01 1 day

0.1

1 week 1 month

1

10

100

1000

Characteristic time scale — years

Figure 11.11 Characteristic time scales of different events and processes. Source: After Celia and Nordbotten (2011).

11.3.2 FEP in practice The FEP approach has been applied in the assessment of storage performance and risk for a number of projects, including the Krechba CO2 project at In Salah, Algeria and the IEA GHG Weyburn CO2 monitoring and storage project in Saskatchewan, Canada among others (see, e.g., Arild et al., 2017; Paulley et al., 2011; Preston et al., 2005). Table 11.5 shows the Weyburn FEP table.

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Table 11.5 FEP table for the Weyburn CO2 monitoring and storage project Weyburn CO2 monitoring and storage project FEP table Rock properties Mechanical properties of rock Stress field Mineralogy and solid organic matter Presence and properties of faults/lineaments Presence and properties of fractures Caprock integrity Hydrogeological properties Cross-formation flow Fluid characteristics of rock Geometry and driving force of groundwater flow system Hydrogeological properties of rock Pore blockage Saline (or fresh) groundwater intrusion Transport pathways Chemical/Geochemical Carbonation Colloid generation Degradation of well seal (cement/concrete) Dissolution of minerals/organic matter Dissolution/exsolution of CO2 Dissolved organic material Groundwater chemistry (basic properties) Methanogenesis Microbial activity Precipitation/coprecipitation/mineralization Reactive gaseous contaminants Redox environment/heterogeneities Mineral surface processes (sorption/desorption) Salinity gradient CO2 properties and transport Advective flow of CO2 monitoring (future) Colloid transport Diffusion of CO2 Dispersion of CO2 Source term (CO2 distribution) Thermodynamic state of CO2 Transport of CO2 (including multiphase flow) Source: After Preston et al. (2005).

Other gas Gas pressure (bulk gas) Release and transport of other gases Geology Seismicity (local) Temperature/thermal field Uplift and subsidence (local) Abandoned wells Annular space (quality/integrity) Expansion of corrosion products (abandoned well metal casing) Corrosion of metal casing (abandoned wells) Boreholes—unsealed (extreme case) Incomplete borehole sealing/early seal failure Incomplete records of abandonment/sealing Non-system (external) FEPs Artificial CO2 mobility controls Climate change Cross-formation flow (fast pathways) Depth of future wells drilled Earthquakes EOR-induced seismicity Extreme erosion Fault activation Future drilling activities Glaciation Hydraulic fracturing Hydrothermal activity Undetected rock features (faults, fractures, etc.) Igneous activity Major rock movement Metamorphic processes Mining and other underground activities Regional uplift and subsidence Hazardous nature of other gases Sea-level change Seismic pumping Seismicity (external)

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Reviews of the FEP list by the project team, specific domain experts, and other stakeholders then resulted in the definition of a base scenario which describes the scope of the system, key assumptions and FEPs to be considered in assessing system performance (Table 11.6). In addition, a number of alternative scenarios were defined for the system, as shown in Table 11.7. These identified additional FEPs which were considered to have the potential to significantly affect system performance under these scenarios and should therefore be subjected to specific assessment. The spatial and temporal scales of this set of significant FEPs as well as the state of data and knowledge in relation to each FEP will then determine the assessment approach, in terms of the types, size, and complexity of models that need to be built. The remaining chapters of Part III address the current state of knowledge of geological storage related FEPs in all relevant disciplines, such as geology, geomechanics, and hydrology. This segregation into disciplines is a convenience that is, of course, not respected by the systems being described. Couplings and interactions across these boundaries are the norm and are addressed once both ends of the interaction have been introduced, e.g., the coupling between flow processes and geochemical reactions is discussed in Chapter 14, once geochemical FEPs have been introduced.

Table 11.6 Weyburn CO2 monitoring and storage project—base scenario Scenario element

Description

System model domain

The Weyburn 75-well patterns and a 10 km zone surrounding it, including all wells within this domain Physical trapping features, which have naturally contained the oil/gas within the reservoir, geochemical effects in the aqueous phase of all aquifers. All FEPs that could affect the storage and movement of CO2 should be considered, including processes such as hydrodynamics, geochemistry, buoyancy and density-driven flow, dissolution of CO2 in water and residual oil, pressure
temperature changes occurring within the geologic formations, and potential well seal degradation The caprock may have natural fractures or discontinuities but all are isolated or sealed such that caprock integrity is not impaired. There is a series of aquifers/aquitards above and below the storage formation, and these formations may contain fractures and fissures The relevant time frame starts with the inception of EOR and finishes as the earlier of 5000 years or the time at which there is 50% loss (to the biosphere) of the CO2 stored at the end of EOR

FEPs to be included

System boundary conditions

Time frame

Source: After Preston et al. (2005).

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Table 11.7 Weyburn CO2 monitoring and storage project—alternative scenarios Alternative EOR options scenario A

B

Leaking wells

Well abandonment

Maximize CO2 Normal Standard storage at increased leakage reservoir pressure Extreme Improved longMaximize EOR by failures term sealing water flush after CO2 injection period capabilities

Tectonic activity

Fault movement

None

None

Possible, low Possible, across probability several formations

Source: After Preston et al. (2005).

11.4

References and resources

11.4.1 References Arild, Ø., Havlova, V., Ford, E.P., Lohne, H.P., Majoumerd, M.M., Havlova, V., 2017. A comparison of FEP-analysis and barrier analysis for CO2 leakage risk evaluation on an abandoned Czech oilfield case. Energy Procedia. 114, 4237
4255. Benson, S.M., Hepple, R., Apps, J., Tsang, C.F., Lippmann, M., 2002. Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations. Lawrence Berkeley National Laboratory report LBNL #51170. Blondes, M.S. et al., 2013. National Assessment of Geologic Carbon Dioxide Storage Resources—Methodology Implementation. US Geological Survey Report 2013
1055, United States Geological Survey, Reston, VA. http://pubs.usgs.gov/of/2013/1055. Bonder, P.L., 1992. Applications of carbon dioxide in enhanced oil recovery. Energy Convers. Manage. 33, 579
586. Celia, M.A., Nordbotten, J.M., 2011. How simple can we make models for CO2 injection, migration and leakage? Energy Procedia. 4, 3857
3864. Condor, J., Unatrakarn, D., Wilson, M., Asghari, K., 2011. A comparative analysis of risk assessment methodologies for the geologic storage of carbon dioxide. Energy Procedia. 4, 4036
4043. Frailey, S.M., Tucker, O., Koperna, G.J., 2017. The genesis of the CO2 storage resource management system (SRMS). Energy Procedia. 114, 4262
4269. Goldberg, D.S., Takahashi, T., Slagle, A.L., 2008. Carbon dioxide sequestration in deep-sea basalt. Proc. Natl. Acad. Sci. USA. 105, 9920
9925. Gunter, W.D., Bachu, S., Benson, S., 2004. The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage of carbon dioxide. In: Baynes, S.J., Worden, R.H. (Eds.), Geological Storage of Carbon Dioxide, Geological Society, London, Special Publications, 233 (pp. 129
145). Han, W.S., McPherson, B.J., 2009. Optimizing geologic CO2 sequestration by injection in deep saline formations below oil reservoirs. Energy Convers. Manage. 50, 2570
2582. Kelemen, P.B., Matter, J., 2008. In situ carbonation of peridotite for CO2 storage. Proc. Natl. Acad. Sci. USA. 105, 17295
17300. Koide, H., et al., 1992. Subterranean containment and long-term storage of carbon dioxide in unused aquifers and in depleted natural gas reservoirs. Energy Convers. Manage. 33, 619
626.

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McGrail, P.B., Schaef, H.T., Ho, A.M., Chien, Y.-J., Dooley, J.J., Davidson, C.L., 2006. Potential for carbon dioxide sequestration in flood basalts. J. Geophys. Res. 111, B12201. Paulley, A., Metcalfe, R., Limer, L., 2011. Systematic FEP and scenario analysis to provide a framework for assessing long-term performance of the Krechba CO2 storage system at In Salah. Energy Procedia. 4, 4185
4192. Preston, C., et al., 2005. IEA GHG Weyburn CO2 monitoring and storage project. Fuel Process. Technol. 86, 1547
1568. Qi, R., LaForce, T.C., Blunt, M.J., 2009. Design of carbon dioxide storage in aquifers. Int. J. Greenhouse Gas Control. 3, 195
205. Shi, J.Q., Durucan, S., 2005. CO2 storage in deep unmineable coal seams. Oil Gas Sci. Technol.—Rev. IFP. 60, 547
558. Wilcox, J., 2012. Carbon Capture. Springer, New York. Wilson, E.J., Johnson, T.L., Keith, D.W., 2003. Regulating the ultimate sink: managing the risks of geologic CO2 storage. Environ. Sci. Technol. 37, 3476
3483. Yamaguchi, K., et al., 2013. Features events and processes (FEPs) and scenario analysis in the field of CO2 storage. Energy Procedia. 37, 4833
4842.

11.4.2 Resources CSLF (Carbon Sequestration Leadership Forum), 2007. Estimation of CO2 Storage Capacity in Geological Media. Phase 2 Report prepared by the Task Force on CO2 Storage Capacity Estimation for the Technical Group (TG) of the Carbon Sequestration Leadership Forum (CSLF). Available at www.cslforum.org/publications. IEA/UNIDO (International Energy Authority/United Nations Industrial Development Organization), 2011. Carbon Capture and Storage Roadmap. Available at www.iea.org/ papers/roadmaps/ccs_industry_foldout.pdf. Heidug, W., 2013. Methods to Assess Geologic CO2 Storage Capacity. IEA Workshop Report. Available at www.iea.org/publications/freepublications. IEEP (Institute for European Environmental Policy), 2010. Review of the public participation practices for CCS and non-CCS projects in Europe (Desbarats, J., Lead author). Available at www.communicationnearco2.eu/fileadmin/communicationnearco2/user/docs/WP1.2_Final_ report.pdf. MIT (Massachusetts Institute of Technology) CCS Technologies Group. Carbon Capture and Sequestration Project Database. Available at: http://sequestration.mit.edu/tools/projects/ index.html. US DOE NETL (National Energy Technology Laboratory). Best Practices for Public Outreach and Education for Carbon Storage Projects. Report DOE/NETL-2009/1391. Best Practices for: Risk Analysis and Simulation for Geologic Storage of CO2. Report DOE/ NETL-2013/1603. Both available at www.netl.doe.gov. Quintessa, 2004. A Generic FEP Database for the Assessment of Long-Term Performance and Safety of the Geological Storage of CO2. Report QRS-1060A-1. Also latest CO2 FEP database, accessible at www.quintessa.org/co2fepdb/v2.0.0/PHP/frames.php. US DOE (US Department of Energy), 2008. Carbon Sequestration Atlas of the United States and Canada (Atlas II). National Energy Technology Laboratory. Available at www.netl. doe.gov/technologies/carbon_seq/refshelf/atlasII. SPE (Society of Petroleum Engineers), 2011. Guidelines for Application of the Petroleum Resources Management System. Available at www.spe.org/industry/reserves.

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From a geological perspective, the main components of a storage complex are as defined in Table 12.1. The geological and geomechanical characteristics of these formations are critical in determining containment and storage capacity and are discussed in the following sections.

12.1

Storage formation type and geometry

The geometry and properties of the formations that make up the storage complex are determined by the geological processes of sedimentation, burial, structuration (uplift, faulting, etc.), possibly diagenesis and so forth, by which they are created, shaped, and altered.

12.1.1 Sedimentary processes The rock formations that contain gas, oil, or water in the subsurface were formed over millions of years by the gradual deposition of sediments—predominantly either silicate or carbonate grains—in a wide range of sedimentary processes such as the deposition of sand bars in meandering rivers, the gradual buildup of sediments on a flood plain or of a delta system at a river mouth, the subsea “rain” of carbonate skeletal material or the deposition of wind-blown sand grains in dune systems, to name but a few. Burial under an increasing thickness of additional sediment results in compaction and eventually the cementation of grains to form a consolidated rock. If the space between the grains remains open the rock will be porous, with a capacity to hold fluids, and if these pores remain connected, the rock will also be permeable— allowing fluids to flow between the pores. Organic material is also transported and deposited in these processes along with inorganic sediments, and subsequent burial and heating results in thermal decomposition of the organic material to produce hydrocarbons. As a result of density differences with the surrounding brine, hydrocarbons migrate upward from the point of origin (commonly known as the “kitchen”) and will eventually reach the surface (forming oil seeps, tar sands, etc.) unless the migration path is impeded by a sealing fault or an impermeable formation and the fluids are trapped, forming an oil or gas accumulation. The vast majority of sedimentary formations are not charged with hydrocarbons and are therefore aquifers, the pore space remaining filled with brine of greater or Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00012-X © 2017 Elsevier Inc. All rights reserved.

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Table 12.1 Components of the storage complex Component formation

Outline description

Storage (or host) formation

The formation or formations into which CO2 will be injected and which form the repository for long-term storage. Most commonly a porous and permeable brine filled sedimentary formation, but other possibilities include unmineable coal seams or basalt The impermeable or very low permeability formation immediately overlaying the storage formation that provides the primary containment for upwardly mobile CO2 One or more impermeable or very low permeability formations above the primary seal that are capable of containing any mobile CO2 that leaks through or around the primary seal The impermeable or very low permeability formation underlying the storage formation that limits the downward movement of CO2 saturated brine

Primary seal (or caprock) Secondary seal(s)

Bottom seal

lesser salinity. Since most sediments are transported by and deposited in bodies of water (fluvial, lacustrine, and marine sediments) the pore water salinity will initially reflect the depositional environment. After deposition, various processes such as the compaction and expulsion of water from clays, mineral dissolution, geochemical reactions, and meteoric water influx may all have an impact on brine salinity. Typically, underground sources of drinking water (USDW) (i.e., potable or near potable aquifers) will be those that remain connected to surface sources of fresh, meteoric water. Three major aspects of the geological formations that are formed by these sedimentary processes are as follows: 1. Structure—the current external architecture of the sedimentary layers as a result of the influence of tectonic forces since deposition 2. Stratigraphy—the internal architecture resulting from the details of the sedimentary processes 3. Heterogeneity—the lateral and vertical variability in formation properties (particularly permeability) as a result of the stratigraphy and other processes such as diagenesis, fracturing, etc.

12.1.2 Storage formation and overburden structure After deposition and burial, tectonic and other forces can result in the uplift and deformation of the formations, which can lead to geomechanical failure (faulting and fracturing). Uplift can also result in surface exposure leading to erosion and dissolution, meteoric water influx, etc., which can have an impact on reservoir properties. The geomechanical processes of deformation and faulting result in the formation of various structural configurations and structural traps are formed when

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deformation, faulting or an erosion surface (known as an unconformity) prevents the upward movement of a buoyant fluid, such as gas, oil, or mobile CO2. Common types of structural traps were illustrated in Figure 11.1.

Faulting Faulting occurs when geomechanical forces, either compressional or extensional, exceed the rock strength (see Section 12.5). Although faults are often illustrated as single features, in most instances failure results in a faulted zone that may contain one or more major plus a large number of smaller faults. Seismic surveys are the main tool for fault identification, although limited spatial resolution means that secondary events within a fault zone are typically unresolved. For simplicity the term fault is used henceforth, but should be understood to include the possibility of a more extensive faulted zone. Faults are characterized by their offset or throw, the direction and angle of the main fault plane, and the sealing capacity, both perpendicular to and along the fault plane. The most important of these characteristics from a geological storage perspective is the sealing capacity. The sealing capacity perpendicular to a fault may be an important structural trapping element, as shown in Figure 11.1B. The main factors that determine whether a fault is sealing are as follows (Figure 12.1): G

G

G

G

Offset—whether the fault offset results in the permeable formation being juxtaposed to an impermeable formation on the other side of the fault Clay-smear (shale-gouge)—fault movement can result in the smearing of clay layers along the fault plane which, if sufficient, can make the fault plane impermeable Cataclasis—the crushing of rock fragments in the fault zone (fault gouge) can eliminate permeability or increase capillary entry pressure Diagenesis—a seal can be formed by diagenetic processes that result in cementation along an initially permeable fault plane

Any given fault may seal as a result of one of these factors alone or a combination acting in concert. Cataclasis is a common feature in faults, but is more likely to result in sealing in the case of strike-slip faults, which may have little vertical offset but significant horizontal movement. Fault seal due to Fault throw

Offset Clay smear

Strike-slip fault

Cataclasis Clay smear

Zone of cataclasis

Figure 12.1 Factors determining sealing capacity across fault planes.

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Ν

Maximum horizontal stress perpendicular to fault–increased chance of fault to be sealing

σH

Maximum horizontal stress parallel to fault–increased chance of fault to be non-sealing

Ν

σH

Figure 12.2 Impact of local stress direction on likelihood of fault sealing.

Sealing capacity along the fault plane is a critical consideration for any fault that might be intersected by a plume of mobile CO2, since a permeable path along this plane may result in leakage through the primary and/or secondary seals. The three factors above also influence sealing capacity in the fault plane, but the most important factor is the current stress regime. If the minimum horizontal stress is neutral or extensional (Figure 12.2), this increases the chance that fault planes perpendicular to that direction will be open and present leak paths for mobile CO2. An understanding of the regional stress regime is therefore essential in order to assess the leakage risk posed by faults that cross the primary or secondary seals, and to direct appropriate monitoring activities.

Open, partially open, and closed systems An important characteristic of the geometry of a storage complex is whether it is an open, partially open, or closed system. An open system is one in which there is no significant long-term increase in the average pressure as a result of the injection of fluid into the pore space. In effect the system behaves as if it is infinite, either as a result of a remote connection to the surface or to a very large, well connected formation pore volume. In contrast the connected pore volume in a closed system is limited; the average pressure increases significantly with the injection of fluid and the maximum permissible pore pressure (to prevent geomechanical failure—see Section 12.5) limits the safely containable injection volume. Between these extremes, a partially open system is one in which the pressure increase due to injection is significant on an operational timescale but pressure dissipates on a longer timescale. This occurs if the pore space is large compared to injected volumes, but is not as well connected as in a fully open system. Flow restrictions in a partially open system could be structural or stratigraphic in nature, for example, due to partially sealing faults or to lower permeability regions in the storage formation.

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12.1.3 Storage formation and caprock heterogeneity In attempting to characterize a sedimentary rock formation, and thereby delineate its potential either for oil and gas exploitation or for geological storage, the most significant problem faced by the geologist is heterogeneity. Internal sedimentary architecture and the presence of fracture systems are the two most important types of heterogeneity.

Storage formation stratigraphy The stratigraphy or internal architecture of a sedimentary formation is a consequence of a wide range of factors, including: G

G

G

Type of depositional environment; fluvial, lacustrine, marine (shoreline, shallow or deep water) environments result in characteristic sedimentary body configurations Characteristics of the sediment supply, including temporal variability Local and global climatic conditions; water input to rivers and lakes affecting suspension and deposition of sediments, impact of sea level rise and fall on water depth, etc.

As a result, trapping of fluids can also occur as a result of the geometric form of a permeable sedimentary body arising from these factors, for example, a marine sediment that gradually becomes more shaly at greater water depths (i.e., during deposition), with finer sediments being deposited further away from the sediment source. This form of trap, known as a stratigraphic trap, was also illustrated in Figure 11.1. Smaller scale stratigraphic heterogeneities can also have an impact on geological storage, as a result of small-scale “structural” trapping of mobile CO2 and also by increasing the gross volume swept out by the migrating plume leading to an increase in residual trapping. Depending on the nature of the sedimentary and other geological processes that have played a part in its history, the storage formation may comprise a number of different rock types, known as rock facies, with varying properties. Identifying rock facies and determining their properties and distribution is an important task in oil and gas practice as this can have a significant impact on hydrocarbon recovery processes and will be equally important for geological storage since differing properties will result in different storage efficiencies for each rock type. This is achieved using geological data overall available scales, from regional models of depositional systems, through seismic and well-log data, to flow measurements on core sample, and electron microscopy of thin section samples. Contrary to oil and gas practice, where heterogeneities are rarely beneficial for hydrocarbon recovery efficiency, for geological storage many types of heterogeneity can have a positive effect on storage capacity. For example, heterogeneities that impede vertical fluid movement will increase the gross rock volume swept by the plume, increasing residual trapping. An example of heterogeneity impeding vertical migration is well known from the Sleipner project (see Chadwick et al., 2009). Mudstone layers within the Utsira aquifer were identified in the initial characterization from well-log data, although the lateral extent of these layers was unknown as they are too thin to be observed in

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2001

1 km Increasing amplitude

1994

2008

CO2 plume in map view

Injection point

2008–1994

1999 2001

2002

2004

2006

2008

Figure 12.3 Time-lapse seismic from the Utsira aquifer at Sleipner. Source: Courtesy Statoil.

the pre-injection seismic. However, time-lapse (4D) seismic monitoring clearly demonstrated the extent of these layers and their impact on plume movement, as shown in Figure 12.3. The impact of this heterogeneity has been significant; as at 2006, capillary trapping below the mudstone layers accounted for 30% of injected volume (Bickle et al., 2007), although the long-term fate of this capillary trapped volume is still uncertain. A further example of the impact of heterogeneity was observed in the Frio Brine Pilot, where the plume arrived at a monitoring well about 20% earlier than predicted due to the presence of a high permeability layer that was not fully reflected in the pre-injection model (Hovorka et al., 2006).

Caprock stratigraphy The primary and secondary seals within a storage complex are typically provided by fine-grained sedimentary units with a high clay content that form impermeable layers following compaction and de-watering of the clays. These sediments are deposited in a low-energy environment where fine sediments can settle (i.e., generally in deeper water) and caprocks therefore tend to be more homogeneous than coarser material deposited in higher energy environments. Lateral variability will still occur, for example, due to changes in depositional water depth, differential compaction, etc. In hydrocarbon reservoirs, the presence of an oil or a gas column is a clear demonstration of the sealing ability of the caprock over a geological timescale (107 to 108 years). Formations that might not provide competent seals for a hydrocarbon reservoir might still provide an adequate primary seal for a storage complex with a required containment timescale 3 or more orders of magnitude shorter. Primary and potential secondary seals in the storage complex therefore need to be characterized in terms of geological storage specific requirements, such as the entry pressure for CO2, potential geochemical impact of CO2 on caprock properties, and so forth.

Fracture systems Fracturing is one example of reservoir heterogeneity which, if extensive in the storage complex, has the potential to dramatically impact both storage capacity

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Table 12.2 In Salah fracture system characterization Formation

Fracture density Fracture (m21) length (m)

Fracture aperture (mm)

Orientation

In Salah primary caprock In Salah storage aquifer

1
3

25
50

0.1
2.0

NW
SE

2
3

6
25

0.1
1.0

NW
SE

and containment. Fracture networks can short circuit migration paths through the rock matrix, reducing the effectiveness of residual trapping, and can cause leakage out of the storage complex if they penetrate through the primary or secondary seals. Natural fractures occur in subsurface formations as a result of geological processes that impose stresses exceeding the strength of the formation. Processes that can result in fracturing include: G

G

G

Structural deformation due to regional or tectonic stresses Uplift and expansion due to rapid erosion of the overburden Compaction due to dewatering of clays or release of high pore pressure fluids

Natural fractures are often, although not exclusively, related to larger scale faulting and the geomechanics of fracturing and faulting are identical (see Section 12.5), the essential difference being one of scale. Fracturing relieves stresses without significant vertical or lateral movement. Fractures may be either open, and provide a conductive path through the formation, or they may be closed, in which case they may potentially be barriers or baffles to flow. Fracture morphology can be affected by mechanical and chemical (diagenetic) processes, which may either enhance or reduce fracture permeability. For example, permeability perpendicular to fracture surfaces may be reduced as a result of mechanical abrasion or deposition of nonpermeable minerals. Along the fracture plane, partial mineralization may contribute to fractures remaining open when a change in external stresses might otherwise have caused them to close. Natural fracture systems are characterized in terms of fracture frequency or abundance (m21), fracture length (m), and aperture or width (mm), as well as the fracture conductivity and orientation. Table 12.2 shows the fracture frequency and length values for the In Salah storage complex. Typically natural fracture systems exhibit fracture porosities of at most a few percent, and therefore do not contribute significantly to storage capacity. However the permeability of a fracture system in the storage formation can have a significant impact on CO2 migration path and speed. Severely fractured formations will not be favored as host formations for saline aquifer storage (see Krechba example below), both because short-circuiting of flow will tend to reduce residual trapping and because fractures extending into the caprock will pose a leakage risk. Fractures will be more beneficial in the case of in situ mineral carbonation, where

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Fracture Vug Matrix

Figure 12.4 Realistic and idealized geometry of fracture systems. Source: After Warren and Root (1963).

a well-developed fracture system will help to increase the contact area between injected CO2 and reactive minerals. Depending on the geomechanical stress history and rock strength, fractures may be present in one, two, or three planes, dividing the formation into planes, “matchsticks” or cubes as illustrated in Figure 12.4. Cores provide an important source of data to characterize the 3D geometry of fracture systems and borehole imaging logs help to close the gap between the core scale (c. 10 cm 3 10 m) and the overall fracture system dimensions. Dense and extensive fracture systems may also be identifiable from 3D seismic, as a result of the impact on the acoustic properties of the formation. The In Salah gas development in Algeria is an example of a project where the behavior of injected CO2 was affected by the presence of a natural fracture system (see Iding and Ringrose, 2009). The gas produced from multiple gas fields at In Salah contains up to 10% CO2, and geological storage has been implemented as part of the project to avoid the emission of the majority of the co-produced CO2. Injection of B1.0 Mt-CO2/year (1.4 3 106 m3/day) into the saline aquifer down flank of the Krechba gas accumulation commenced in 2004 (Figure 12.5), with about 17 Mt-CO2 expected to be stored during the life of the project. Natural fractures were not highlighted as a significant feature of the gas field development planning for the Krechba field (due in part to the lack of large-scale faulting in the field), although the presence of an open fracture system, related and aligned to a NW
SE fault trend, was identified in other nearby gas fields developed as part of the project. Fractures were however identified during the drilling of the horizontal injection wells (initially as a result of drilling mud losses into the most permeable fractures), and the fracture network was subsequently characterized using cores and borehole image logs as well as detailed seismic studies to identify

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Amine CO2 removal

Gas export

CO2 injection wells

Production wells

Silts and limestone

Pan-Saharan shallow aquifer Mudstone caprock c. 900 m thick

Gas accumulation

Potential caprock flow paths

Tourasian sandstone reservoir c. 1900 m deep, 20–25m thick

Figure 12.5 Schematic of the Krechba field development at In Salah, Algeria. Source: After Iding and Ringrose (2009).

the small-scale fault system related to the fracture network. The impact of the fracture system on the footprint of the plume has also been demonstrated through surface deformation measured using time-lapse or differential interferometric synthetic aperture radar (DInSAR). The presence of a fracture system extending into the caprock provides a possible leak path for injected CO2 and is therefore a potential risk to containment. The gas accumulation at Krechba demonstrated the long-term sealing capacity of the caprock, at least above the gas accumulation, but left open the possibility that caprock integrity may be affected off structure—for example, the spill point of a structure could be determined by a down flank fracture network. Modeling of fracture systems in order to quantify their impact on plume behavior is problematic as a result of the complex nature of typical fracture systems, particularly when compared with their simplistic representation in flow simulations, as illustrated in Figure 12.4. Flow modeling of a fracture network can be achieved using a discrete fracture network (DFN), as shown in Figure 12.6. Incorporating this explicit fracture detail significantly increases computational requirements when compared to non-fractured models and would typically only be used over a sector of the storage formation. In non-fractured models, the impact of the fracture network would be incorporated by locally enhancing the permeability in the region of the model where the fracture system is present. The geometry and

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Figure 12.6 Example of the discrete fracture network (DFN) used in Krechba fracture modeling. Source: From Iding and Ringrose (2009), with permission.

properties of this region would then be adjusted to match the observed behavior of the plume.

12.2

Storage formation and caprock properties

12.2.1 Porosity Porosity, denoted by the Greek letter Φ and expressed as a fraction or percentage, is the proportion of the gross rock volume that is occupied by pore space. In sedimentary rocks such as silts and sandstones, the intergranular pores provide the primary porosity, although additional (secondary) porosity can occur as a result of diagenesis—geochemical changes after deposition—or as a result of the presence of fractures. In carbonate rocks the pore system is generally more complex, with intragranular pores, vugs, and fractures often contributing significantly to the total porosity. The pore system provides both the fluid storage capacity of a rock and also the flow path for fluid movement.

Total and effective porosity A distinction is made between the total porosity of a rock, which includes all pore space whether or not it contributes to flow, and the effective porosity, which excludes any pores that are isolated from the pore network (isolated porosity) as well as the pore volume occupied by water bound to clays under in situ conditions. This clay-bound water will be expelled if extreme drying conditions ( . 100 C) are used in the preparation of core samples for porosity measurements.

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Measurement of porosity Formation porosity can be directly measured only at the centimeter and decimeter scale, by recovering rock samples from wells—either as cores or drill cuttings. Total porosity is typically determined by measuring the bulk volume of a cleaned and dried sample before and after crushing, while effective porosity is measured by injecting helium into a sample that has been prepared under controlled humidity conditions to prevent the loss of clay-bound water. Total porosity can also be inferred on a decimeter scale from geophysical surveys in wells. Survey tools directly measure the electron density of the rock surrounding the wellbore using Compton scattering of high-energy gamma rays and the hydrogen content using high-energy neutron scattering. These measurements can be corrected for borehole effects and interpreted to give total porosity for a known rock type. Core plug measurements are used to calibrate the algorithms used to derive values from well logs. In well logging, porosity is conventionally expressed in porosity units (PUs) where 1% porosity is equal to 1PU, and these log-derived porosity values are typically subject to measurement uncertainties in the order of 1PU.

12.2.2 Permeability The permeability of a rock is a measure of its ability to conduct fluids and is determined by the nature of the pore network. A well-connected network with large poreto-pore connections (pore throats) results in a high permeability, while rock with small or poorly connected pores will exhibit low or zero permeability. The conventional unit of permeability, the Darcy, is named after French engineer Henry Darcy who, in the 1850s, was the first to study the flow of water through sand beds. The absolute permeability of a formation is the permeability when a single fluid is flowing, and this is typically determined by flowing air through a cleaned and dried core sample and interpreting the flow rate and pressure data using Darcy’s Law (Chapter 13). Permeability measurements made using gas are generally higher than would be measured using a liquid (the Klinkenberg effect), since the gas velocity at grain surfaces may be non-zero while a liquid would have a stationary boundary layer. Measurements at several gas flow rates can be used to correct for this effect. Permeability is affected by the stress applied to the sample, and special core holders can be used to make measurements under simulated in situ stresses. In situ permeability can also be determined by conducting small-scale flow tests using a well logging (formation tester) tool or by doing full-scale production or injection tests on a formation. The permeability to each fluid when more than one fluid is present is termed the relative permeability and is discussed in Chapter 13. Figure 12.7 shows an example of core plug porosity and permeability measurements for part of the Frio “C” formation, and also the way these have been averaged (upscaled) in a 3D numerical model.

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Depth (m) 1540

1545

1550

1555

1560 0

0.1

0.2

0.3

0.4

0

Porosity

1000

2000

3000

4000

Permeability (mD)

Figure 12.7 Core measured porosity and permeability for part of the Frio “C” formation. Source: After Hovorka et al. (2006).

In the static geological model, permeability values are often assigned to the rock volume that has not been sampled by cores or well test data using a correlation between the permeability (k) and porosity (Φ). This is typically a logarithmic relationship of the form: Φ 5 a 1 b logðkÞ

(12.1)

where a, b are constants to be determined for each rock facies. In some cases, particularly in carbonate rocks where various geochemical processes may have occurred since deposition (diagenesis), this type of relationship may be very approximate or absent. Figure 12.8 shows an example of the dependence of permeability on porosity for core samples from the Frio sandstone. Symbols in the figure indicate different types of sand facies.

Horizontal and vertical permeability The permeability of a sedimentary rock will generally be greater when measured horizontally (i.e., in the plane of the geological bedding) rather than vertically (perpendicular to the bedding). In high permeability, very homogeneous formations the ratio of vertical to horizontal permeability (kv/kh) may be close to unity, but in layered (heterolithic) formations this ratio may be 0.1 or lower. The vertical permeability (kv) is an important factor in geological storage since unconstrained buoyant plume migration will occur in a vertical direction and, as will become apparent after the discussion of Darcy’s law (Section 13.2), the gross rock

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Permeability (kh)

1000 100 10 1 0.1 0.01 0

5

10 15 20 Core porosity (%)

25

30

Figure 12.8 Air permeability versus porosity for Frio sandstone core samples. Source: After El-Mowafy and Marfurt (2016).

volume swept by the migrating plume is inversely proportional to the vertical permeability, a lower kv resulting in a higher swept volume and consequently higher residual trapping. Unlike horizontal permeability, which is largely scale independent, the issue of scale needs to be carefully considered when determining kv. For example, a kh value determined on a core plug will generally be the appropriate kh to use on a 100 m scale, whereas a core plug kv will rarely be appropriate on more than a decimeter scale. This is because sedimentary heterogeneities, such as low permeability layers or impermeable mudstones, will reduce the effective kv on a length scale that includes this variability. This process—starting with fine scale (cm to dm) measurements of a property such as permeability and establishing an appropriate value for use in numerical modeling studies on a grid block scale (10 m to 100 m)—is known as upscaling. Various semi-empirical methods of estimating the effective kv (kve) in heterolithic formations have been proposed. For example, for a sandstone formation containing frequent discontinuous impermeable shale layers, Begg and King (1985) used streamline simulation to derive the following approximate estimate for kve: kve 5 kh ð1
Vsh Þ=ðkv =kh 1fL=2Þ2

(12.2)

where Vsh is the volume fraction, f is the frequency of occurrence (m21) and L is a mean length (m) of the shale layers, and kv and kh refer to the permeability of the sand within which the shale layers are embedded. The validation of the approximation, on a vertical scale that includes about 10 or more shale layers, has been confirmed using simple 3D simulation models. Figure 12.9 shows kve/kh based on this relationship for varying Vsh and (fL) and for kv/kh 5 1.

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Permeability ratio (kve/kh)

0.5 0.4 f•L

0.3

1

0.2

2

0.1

5 10

0 0

0.1

0.2

0.3

0.4

0.5

Shale volume fraction (Vsh)

Figure 12.9 Example of shale layer impact on effective vertical permeability.

Clearly, the combined frequency 3 length of impermeable layers can have a dramatic influence on this important parameter.

Caprock permeability The permeability of the caprock if of crucial importance for containment, as this provides the primary seal of the storage complex, and permeabilities in the microto nano-Darcy range (10218 to 10223 m2) are typical for formations that commonly seal hydrocarbon accumulations. Measurement of permeabilities in this range can be made using the steady-state gas flow-through method discussed above or by the transient pulse decay method, in which a pressure pulse is applied to the upstream end of a sample and permeability is determined from the exponential decline of the upstream pressure as gas leaks off into the sample. High clay content is a given in siliciclastic caprocks, but the distribution of clays within the fine-grained matrix can result in much greater permeability anisotropy than in permeable storage formations. In the Krechba field, kh/kv ratios of up to 50,000 were measured in caprock samples with khB10217 m2 containing just 20% clay, due to millimeter scale chlorite layering, while similar samples with more homogeneously distributed clays had kh/kv ratios in the more typical range from 10 to 100. The permeabilities of the upper and lower bounding layers of the storage complex are an important factor in determining the far-field pressure response to injection. Although the permeability of these “sealing” layers is very low, vertical flow over ten or hundreds of km2 can still play a significant part in dissipating pressure buildup. Basin-scale modeling studies (see, e.g., Cavanagh and Wildgust, 2011) suggest that, for 20
50 m thick bounding layers, permeability in the micro-Darcy range is required to maximize storage capacity while, for permeability in the nano-Darcy range, excessive pressure buildup would significantly reduce effective capacity.

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Fracture permeability The permeability of a fracture system can be estimated using Poiseuille’s equation for flow rate in terms of pressure drop along a conduit, together with assumptions about the fracture dimensions and frequency, the permeability of an individual fracture being proportional to the cube of the fracture width (b3). Flow tests in wells are also used for fracture system characterization, including permeability assessment. During injection operations, monitoring data such as 4D seismic can indicate whether a fracture system has been encountered by the migrating plume, and the localized impact of the system on the vertical and horizontal permeability of the storage formation may be determined by matching such data to the modeled performance of the storage system. This model matching approach was used in the Krechba field (discussed above; see Durucan et al., 2011) and resulted in an estimated fracture permeability in the range of 150
300 mD, depending on the extent of the fracture system, compared with matrix permeability of below 10 mD. The early arrival of mobile CO2 at an existing gas production well was attributed to the opening of an existing fault/fracture system, yielding a localized B50 m-wide fault/fracture corridor with a permeability in the range of 1
4 D.

12.2.3 Processes affecting porosity and permeability The effective porosity and permeability of both the storage formation and caprock can be affected by a number of processes occurring during injection and migration of CO2, including dissolution and precipitation of minerals such as calcite, and formation drying, including the dissolution in CO2 of clay-bound water. Geochemical reactions may also be enhanced by microbial action, whether naturally occurring or engineered. These processes may result in enhancement or reduction of the effective porosity and permeability, with potentially important impact in the vicinity of the injection well, and will be further discussed below once the corresponding solubility, geochemical and biological processes have been introduced.

12.2.4 The static reservoir model The structure and formation properties so far described are the components from which a “static” geological model of the geological system can be built. These components and their respective data sources and outline workflows are summarized in Table 12.3. The static model will later be extended to include other facies dependent properties, such as capillary pressure and relative permeability, and an initial fluid distribution as the starting point for dynamic modeling.

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In situ stress and pore pressure

The in situ stress in a porous medium, also known as the poro-elastic stress, is a measure of the grain-to-grain pressure at any point and the pore pressure—the pressure exerted by the fluid occupying the pore space, acting in opposition to external compressive forces—has a direct and important impact on in situ stress. Stress is measured as the force per unit area acting at a point which, in relation to any plane through that point, may be resolved into normal and shear components (Figure 12.10). Table 12.3 Components of the storage complex static model Static model component

Data sources and workflows

Structure (formation depths, gross thickness, location and throw of faults)

3D seismic, time-to-depth calibrated against well data, provides the main structural input. Reference, low and high structure, and gross thickness cases are generated to prove the basis for estimating uncertainty ranges Core and well log data, guided by conceptual depositional models, are the basis for identifying the rock types that are present. In some instances correlations can be established between seismic attributes and rock facies and can be used to assign facies throughout the 3D volume. Reference, low and high cases can be defined to reflect the uncertainty in 3D distribution resulting from the low data density (in most cases) Core analysis provides the hard property data for each identified rock type, with a calibration to well log data being used to assign properties outside cored intervals. Uncertainty ranges will be defined based on measurement uncertainty

Rock facies classification and distribution

Rock facies properties

Fp Fn

F

Unit area

Figure 12.10 Force components and stresses on a plane.

σ = Fn / A τ = Fp / A

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321

Normal stress components, perpendicular to the plane under consideration, are denoted by the symbol σi, with the subscript i indicating one of three Cartesian axes; compressive normal stresses are conventionally positive and tensional stresses negative. Shear stresses, parallel to the plane under consideration, are conventionally positive in a counterclockwise direction and negative in a clockwise direction. Unlike the normal stress convention, this is not unique as the shear stress direction will depend on which side of the plane it is being viewed from. Shear stresses are denoted by the symbol τ, with the shear stress in the i direction due to a force in the j direction being denoted by τ ij.

12.3.1 Principal stresses and Mohr’s circle A suitable choice of axes (the principal axes of stress) will make shear stresses vanish, and the corresponding stresses in these directions are known as the principal stresses, with σ1 being conventionally the maximum, σ3 the minimum, and σ2 the intermediate principal stress. In subsurface formations that are not subjected to significant tectonic forces, σ1 is in the vertical direction due to the lithostatic pressure of the overburden, but significant compressional forces can result in σ1 being in or close to the horizontal plane. In situ stresses are sometimes designated as σv, σH, and σh for the vertical, maximum, and minimum horizontal components, respectively, so that, in many cases, σv 5 σ1, σH 5 σ2, and σh 5 σ3. Considering the two-dimensional case, the stresses at a general angle θ to the first principal stress are given by: σ 5 1/2ðσ1 1 σ2 Þ 1 1/2ðσ1
σ2 Þ cos2θ

(12.3)

τ 5
1/2ðσ1
σ2 Þ sin2θ

(12.4)

and plotting these values gives the diagram known as Mohr’s circle, shown in Figure 12.11. The diagram shows that the maximum shear stress τ occurs for 2θ 5 6 π/2, i.e., at θ 5 45 degrees and 135 degrees. When combined with the Coulomb failure criterion, discussed below, this diagram is a very useful tool for analyzing the conditions τ σ2

σ2

2θ

σ1

σ

σ σ1

θ

τ

σ1

σ2

Figure 12.11 Principal stress nomenclature and Mohr’s circle in two dimensions.

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(A)

(B)

τ

τ

σ3

σ2

ΔP

σ1 σ

σ

Final stress state

Initial stress state

Figure 12.12 Mohr’s diagram: (A) for a triaxial stress state (σ1 . σ2 . σ3) and (B) impact of pore pressure increase ΔP.

for rock failure. The diagram can be plotted once σ1 and σ2 are known and allows the stress in any direction to be calculated. Many geomechanical problems can be solved in two dimensions, for example, the question of fault reactivation (see below) can be solved in a plane perpendicular to the fault plane. More generally, when three dimensions are required to be considered and the principal stresses are unequal (σ1 . σ2 . σ3), the stresses are plotted as three separate circles on the Mohr diagram, as shown in Figure 12.12. Each circle plots the stress components in a plane perpendicular to one of the principle axes, for example, circle C1 plots possible stress states in planes perpendicular to the first principal stress (σ1) axis. Allowable stress components on all planes must lie inside the largest circle and outside the two smaller circles as shown by the shaded area in the figure. Increasing pore pressure opposes the grain-to-grain forces, isotropically reducing all stresses in the formation and shifting the Mohr’s diagram to the left (Figure 12.12B). This will be discussed further in Section 12.5 in relation to faulting and fracturing. During storage operations, an increase in pore pressure will occur locally around an injection well due to the pressure required to drive viscous flow and will also occur over a larger volume in the storage complex in order to accommodate the total volume of injected fluid. The magnitude and duration of these pressure increases will depend on many factors, including the injection rate and duration, the formation permeability and thickness, storage formation connectivity (open or closed system), permeability of the caprock and lower sealing formations, and the total compressibility of storage system (for closed systems).

12.3.2 Determination of in situ stress orientation and magnitude The direction of the maximum horizontal stress can be determined by measuring the ellipticity of a borehole using a 4- or 6-arm caliper, since borehole “breakout” aligns with the maximum horizontal stress. This can be seen from the equation, first

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323

σH σH

Reduced mean stress

σh

Increased mean stress

Borehole

Tensile fractures at the points of maximum stress reduction

Caving from shear failure at the points of maximum stress concentration

σh

σh

σH σH

Figure 12.13 Stress around a borehole and resulting borehole failure mechanisms.

published in 1898 by German engineer Ernst Gustav Kirsch, which gives the circumferential stress around a borehole as: σθ 5 σH 1 σh 2 2ðσH 2 σh Þ cos2θ 2 Pw

(12.5)

where Pw is the fluid pressure in the well and other quantities are as previously defined. The circumferential stress therefore reaches a maximum value (σθ 5 3σH 2 σh 2 Pw) for θ 5 π/2 and a minimum value (σθ 5 3σh 2 σH 2 Pw) for θ 5 0. As a result, the borehole wall will be prone to compressive failure in the direction of σh and tensile failure in the direction of σH, and this failure can be induced by operational excursions in Pw. This borehole failure mechanism is illustrated in Figure 12.13, which shows the stress field around the well and the impact of failure on borehole geometry. The magnitude of the minimum horizontal stress (σh) can be determined from hydraulic fracturing tests. Minifrac tests, using formation testing tools, initiate hydraulic fractures over a B1 m interval in a borehole and enable the minimum horizontal stress to be interpreted from repeated fracture opening and closure pressures recorded downhole. The orientation of the minimum horizontal stress can also be determined by running electric or acoustic borehole imaging logs before and after the minifrac tests to identify the fracture orientation. The vertical, or overburden, stress (σv) can be determined by integrating the overburden density as determined from well log data.

12.3.3 Pore pressure measurement Pore pressures are commonly measured during drilling operations using formation testing tools, run either on an electrical wireline or as part of the drilling assembly

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and, as noted above, these tools can also be used to make spot measurements of formation permeability. Initial pore pressures can also be determined as part of a full production or injection test, although this is a significantly more expensive operation and would normally be conducted only if it was necessary to confirm productivity or injectivity on a reservoir scale (rather than the cm scale tested by cores and formation testing tools). During injection operations, the average pressure in the storage volume can be determined by conducting a pressure falloff survey, which involves the recording of the pressure decline after the cessation of injection. Accuracy will be improved if a downhole pressure gauge is used, since the phase and density changes that will occur in the wellbore during the pressure falloff would make it more complex to extrapolate to average reservoir pressure from wellhead pressure.

12.4

Mechanical rock properties

12.4.1 Rock compressibility The compressibility of the rock is defined as the change in bulk volume (Vb) resulting from a change in the effective stress. In the subsurface, the relevant effective stress change arises due to changes in the pore pressure, so that the bulk compressibility (Cb) is defined using the relationship: ΔVb =Vb 5 Cb ΔPp

(12.6)

Similarly, the pore volume within a rock (Vp 5 Φ  Vb) will change with the effective stress, as a result of the pore compressibility: ΔVp =Vp 5 Cp ΔPp

(12.7)

If injection of a pore fluid takes place into a closed system, the injected volume is accommodated as a result of an increase in pore pressure inducing an increase in the available pore space and a decrease in the volume of the compressible pore fluids. An important consideration in estimating the volume that can be injected into such a system will be the maximum allowable pressure to prevent reactivation of existing faults or fractures, or the creation of new hydraulic fractures (discussed in Section 12.5). For a given maximum allowable pressure increase (ΔPmax) the capacity of the system, defined as the maximum permissible injection volume, is given by: ΔVmax 5 Vp ðCp 1 Cf ÞΔPmax

(12.8)

where Cf is the volume weighted average compressibility of pore fluids within the closed system. The mass of injected fluid that can be accommodated will be given by: mmax 5 ΔVmax ρ

(12.9)

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where ρ is the density of the injected fluid at the final pressure (Pmax). Equation (12.8) assumes that the storage formation is contained within rigid boundaries, so that only the pore and fluid compressibility need to be considered. However, if the host formation contains or is bounded by impermeable but compressible formations, the compression of these formations will yield additional storage space for a given ΔPmax or, in an open system, will attenuate the pressure pulse caused by injection. This attenuating effect has been observed in studies of the Carrizo-Wilcox aquifer, Texas, USA by Nicot et al. (2009), who noted the importance of assessing the compressibility of non-storage components of the storage complex for proper assessment of capacity and far-field pressure effects.

12.4.2 Tensile and compressive strength The tensile and compressive strengths of a rock (T0, C0) are the maximum tensile or compressive stress that the rock can hold before failure occurs. In general T0 is significantly lower than C0 for rocks, with T0/C0 typically being in the range of 1/8 to 1/12. Ranges of rock strength for some rock types relevant to geological storage are shown in Table 12.4. Compressive strength is measured by applying an increasing stress to a rock sample, typically a cylinder of rock drilled from a core; C0 is equal to the applied force at failure divided by the cross-sectional area of the sample. The sample may be laterally unconfined, in which case a uniaxial or unconfined compressive strength is measured, or it may be subject to lateral confining stress to determine triaxial compressive strength. Tensile strength is more difficult to measure directly and is generally measured indirectly using the so-called Brazilian test in which a disc-shaped sample is stressed across a diameter. At failure, T0 is equal to the applied force divided by πrh, where r and h are the radius and thickness of the disk. Rock strength depends on the small-scale geological characteristics, including grain size distribution, grain surface roughness, cementation, and the presence and distribution of clays; correlations between porosity and rock strength are often used to extrapolate core measurements to uncored intervals. Table 12.4 Uniaxial compressive and tensile strength ranges for geological storage relevant rock types Rock type

C0 (MPa)

T0 (MPa)

Basalt Limestone Sandstone Siltstone Shale

50
150 50
100 20
100 40
100 20
200

3
20 4
10 5
10 3
10 1
20

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12.4.3 Thermo-elastic stress If an injected fluid is at a lower temperature than the surrounding rock, the resulting cooling of the rock matrix will cause thermal shrinkage and a corresponding reduction of the in situ stress. This so-called thermo-elastic stress is given by: ΔσT 5 αT EΔT=ð1 2 νÞ

(12.10)

where ΔT is the temperature difference (Trock
Tfluid), E is Young’s modulus, ν is Poisson’s ratio, and αT is the coefficient of thermo-elasticity. An example of thermo-elastic stress is given in Table 12.5 for some typical caprock and aquifer rock characteristics. The impact of cooling and the resulting thermo-elastic stress on Mohr’s circle is shown in Figure 12.14. Although the thermal shrinkage is typically isotropic, the reduction in the vertical stress will generally be less than ΔσT since the overburden is able to partially respond to the local shrinkage. The result is that σ2 and σ3 reduce more than σ1 (taking the principal stress axis as vertical), the outer (σ1, σ3) circle increases in radius and the whole diagram shifts to the left, increasing the risk of rock mechanical failure as will be discussed in the next section.

Table 12.5 Thermo-elastic stress example for caprock and storage formation Parameter

Caprock value

Coefficient of thermo-elasticity, αT Young’s modulus, E Poisson’s ratio, ν Thermo-elastic stress/ C, ΔσT/ΔT

25

1.2 3 10 20 0.15 0.28

Aquifer value 25

1.2 3 10 6.0 0.2 0.09

τ

Δσ3T

Δσ2T

Δσ1T σ

Cold rock stress state

Hot rock stress state

Figure 12.14 Impact of cooling and thermo-elastic stress on Mohr’s circle.

Units C21 GPa — MPa/ C 

Geological and geomechanical features, events, and processes

12.5

327

Faulting and fracturing

The creation of fractures or the reactivation of existing faults or fractures in the storage formation or caprock can have a significant impact on the movement and containment of injected CO2. These important geomechanical processes are discussed in this section.

12.5.1 Rock failure criteria Shear failure of a rock will occur along a plane when the shear stress exceeds the strength of the rock. The shear stress at failure will depend on the normal stress (σ) across the failure plane, and the general failure criterion will be: τ f 5 f ðσÞ

(12.11)

where τ f is the shear stress at failure and f (σ) is some function to be defined. The simplest such function is a linear relationship (τ f 5 a 1 b  σ), which is illustrated in Figure 12.14, together with a Mohr’s circle touching the failure line. The circle therefore represents the stress state in a rock at failure (the critically stressed state)—in this case a rock undergoing uniaxial compressive failure. The point where the Mohr’s circle reaches the x-axis to the right gives the maximum principal stress (σ1) in the rock at failure with σ3 5 0 and is therefore the uniaxial or unconfined rock strength (σ 5 C0). The value of τ where the failure line crosses the y-axis is known as the cohesive strength of the rock (S0). The linear relationship can therefore be written: τ f 5 S0 1 μσ

(12.12)

where μ is the coefficient of internal friction of the rock: μ 5 tanðϕÞ

(12.13)

and ϕ is the angle of internal friction. Equation (12.12) is known as the Mohr
Coulomb failure criterion. The Mohr
Coulomb criterion is a convenient simplification to illustrate the principles of fracturing and fault reactivation. In practice the failure envelope for undisturbed rock will be non-linear, with a gradient that increases at lower stress and decreases at higher stress, reflecting non-elastic behavior such as grain deformation and crushing. A failure envelope of this general form is also shown in Figure 12.15, the point where the failure line reaches the negative x-axis representing failure in tension, at which point σ 5 2T0, the rock tensile strength.

12.5.2 Hydraulic fracturing Hydraulic fracturing is widely used in the oil and gas industry to improve the productivity or injectivity of low permeability formations. The productivity or

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Mohr–Coulomb failure criterion

τ

General τ = f (σ) failure envelope

S0 2β σ

φ –T0

C0

Figure 12.15 Mohr
Coulomb failure criterion.

injectivity of the well benefits from the enhanced flow area provided by the fracture surface.

Fracture initiation Recalling Figure 12.12, increasing the pore pressure in a formation above its initial value (Pi) by injecting a fluid, reduces the effective stresses and moves the Mohr’s circle to the left. Rock failure—fracture initiation—will occur when the pressure reaches the critical value at which the Mohr’s circle touches the Mohr
Coulomb failure line. In a well, stress concentration around the borehole has an influence on fracture initiation and, for a vertical well, a vertical fracture plane will be created perpendicular to σh, (parallel to σH), when the circumferential stress exceeds the rock tensile strength. Ignoring the effect of fluid leak-off into the formation, this occurs when the fluid pressure in the well (Pwf) is given by: Pwf 5 3σh 2 σH 1 T0 2 Pi

(12.14)

In the case of an inclined or horizontal well, the initial fracture orientation close to the well is further affected by the borehole inclination and by local geological heterogeneity, resulting in a tortuous fracture plane that will “twist” into a σh normal plane at some distance from the well. If the fracture closes then, since tensile failure has already occurred (i.e., after fracturing T0 5 0), the fracture will reopen if the excess well pressure exceeds the minimum horizontal stress. In practice, this more conservative condition is often used to estimate the maximum pressure in a well to avoid fracture initiation, since the formation tensile strength may be locally close to zero, for example, if preexisting fractures are present.

Fracture propagation Once a fracture has been initiated the pressure of the driving fluid will need to be maintained at or above Pwf to keep the fracture open. In oilfield practice a proppant

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329

Similar internal friction assumed τ

Shale

Formation not critically stressed

Similar rock cohesion S assumed 0

σ

φ σ3

Fracture contained at base of shale

σ1 σ1 reduced at shallower depth

σ3 typically higher in shale

Injection–induced fracture plane

τ S0 Aquifer

σ

φ σ3

σ1

Figure 12.16 Hydraulic fracture containment by stress contrast.

material is injected to fill the fracture and hold it open when the hydraulic pressure is released. As a fracture propagates from a well out into the formation, the fracture “wings” grow more in the upward than the downward direction. This is simply because, in a homogeneous formation, stress increases with depth, so that fracture propagation will occur more easily toward shallower depth. In line with Equation (12.12), vertical propagation of a fracture is controlled by the contrast in horizontal stress and rock strength between adjacent formations, with stress contrast usually being the dominant factor. Vertical fracture growth from a permeable formation into an overlying shaly caprock formation is often impeded by the in situ stress contrast between these formations illustrated in Figure 12.16, but will not be prevented if the driving fluid pressure within the fracture is sufficiently high. As noted above, if the injected fluid is cooler than the formation, the resulting thermo-elastic stress will reduce the fracture initiation and propagation pressure. As was shown in Table 12.5, the thermo-elastic stress can be in the order of 0.1
0.3 MPa/ C for typical formation properties, and a few degrees temperature difference can therefore significantly reduce the maximum injection pressure if fracturing is to be avoided. The temperature at the injection point depends on the fluid temperature at the well-head and on the heat transfer down the wellbore, which in turn depends on the injection rate. Thermo-elastic stress can potentially reduce the maximum non-fracturing injection rate by a factor of 10
100 for moderate to high permeability formations. It is therefore likely that some geological storage projects will operate under fractured injection conditions and will need to control and monitor fracture propagation to avoid any leakage risk.

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12.5.3 Fault and fracture reactivation If the stresses on a fault plane are such that the fault is close to failure, i.e., the fault is close to being critically stressed, an increase in pore pressure due to nearby injection can cause fault reactivation resulting in fault movement and/or the opening up of a leak path.

Mechanics of fault reactivation The condition for initiation of slip along pre-existing faults or fractures is most usefully defined in terms of the critical pore pressure for reactivation of slip (Pcs). For a fault having a random orientation, the Mohr
Coulomb failure criterion defines the onset of slip for a critical pressure given by: Pcs 5 σm 1 Cf cotðϕÞ 2 τ m =sinðϕÞ

(12.15)

where Cf is the internal cohesion of the fault; as above, ϕ 5 arctan(μ), where μ is coefficient of static friction on the fault; the maximum shear stress τ m 5 (σ1 2 σ3)/2, and the mean stress in the (σ1,σ3) plane, σm 5 (σ1 1 σ3)/2. This failure condition is shown graphically in Figure 12.17, where failure lines are shown both for a cohesionless fault (Pcs 5 ΔP1) and for a fault with non-zero Cf (Pcs 5 ΔP1 1 ΔP2) indicating the additional pore pressure increase (Cf cot(ϕ)) required to overcome fault cohesion. All possible planar faults are represented by points within the shaded area, and the horizontal distance to the failure line from any point indicates the pore pressure for reactivation. Since the coefficient of internal friction of a fault or fracture cannot generally be measured, it is usual in determining the critical pore pressure to make the conservative assumption that Cf 5 0, and for a typical value of ϕ 5 30 degrees, Equation (12.15) then reduces to: Pcs 5 ð3σ3
σ1 Þ=2

(12.16)

As discussed above, thermo-elastic stress would further reduce this critical pressure if the cooling effect is extensive enough to reach the fault plane. τ

ΔP2

ΔP1 τm

Cf

σ

ϕ σ3 ΔP2 = Cf cot (ϕ)

ΔP1 = σm – τm/sin (ϕ)

Figure 12.17 Critical pressure (Pcs) for the onset of shear slip.

σm

σ1

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2500 m

Fault slip tendency High

2500 m

W Low

S

N E SH

Depth: 0 m

Depth: 2900 m

Figure 12.18 Slip tendency on a realistic fault surface. Source: After Streit et al. (2005).

Faults that are most at risk of reactivation are those with an orientation that is “consistent” with the present stress regime in the sense that faulting could have occurred under higher stresses with the current stress orientation. Thus, most at risk in a normal faulting regime are faults parallel to σH, or, in a strike-slip regime, near-vertical faults oriented 6 30 degrees to σH. Faults that occurred under different stress regimes, at earlier geological times, would be less prone to reactivation. The geometry of actual faults is of course far from planar, and the slippage risk of any actual fault will vary over the irregular surface as a result of the varying orientation and friction coefficient. This is illustrated in Figure 12.18, which gives an indication of the variation of critical reactivation pressure on a realistic modeled fault surface. The pore pressure in the fault surface is close to critical in areas with high slip tendency and is well below critical in areas with low slip tendency. If fault reactivation does occur as a result of pore pressure increase, the impact on fluid flow will depend on the areal extent of the slippage and the magnitude of permeability change within the fault plane. For example, permeability in a previously conducting fault or fracture system may increase, while in a fault sealed by clay gouge or a fracture system in a ductile caprock there may be no change in permeability. A full assessment of the reactivation consequences for high-risk faults and the fracture-permeability behavior of the caprock will be an important aspect of site characterization (see Carey and Frash, 2017).

12.5.4 Induced seismicity Faulting or fault reactivation has been observed to produce moderate seismic events (moment magnitude (MW) in the range of 3 , MW , 5), as a result of activities such

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as the injection of waste fluids at deep disposal sites, dam construction, and hydrocarbon production. Notable injection and production examples have been at the Paradox Valley Unit brine injection site in Colorado, USA where a maximum event of MW 5 4.3 was recorded in May 2000, and at the giant Groningen gas field in the Netherlands, where numerous events up to MW B 3.6 have occurred. Although no events with MW . 2 have yet been observed in the few active geological storage operations (In Salah MWmax 5 1.7, Decatur MWmax 5 1.26, Lacq-Rousse MWmax 5 20.3), the risk was highlighted by Zoback and Gorelick (2012) and has been extensively studied since then. As well as the conditions for faulting or fault reactivation discussed above, several additional factors will determine whether such an event has a significant seismic impact.

Fault rupture area and displacement The moment magnitude of an earthquake (MW) is given by: MW 5 2=3log10 ðμAdÞ
6:1

(12.17)

where μ is the shear modulus (Pa), A is the area of the rupture (m2), and d is the average slip on the rupture area (m). Estimating the term μAd may be approached in two ways; the stress release in a slip event Δσ is given by: Δσ 5 μd=Ld

(12.18)

where Ld is the rupture length in the slip direction. The rupture area of small events is approximately circular, so that A 5 πL2/4, where L is the rupture length and Ld 5 πL/4, so that: μAd 5 Δσðπ=4Þ2 L3

(12.19)

The stress release Δσ in small to moderate earthquakes is typically in the range of 0.1
10 MPa, and Figure 12.19 shows MW versus L for these values, using this approach. Alternatively, fault and earthquake studies give rules of thumb for α 5 d/L. For faults with L , 10 km, α B1022 is observed, tending toward 1021 for L . 10 km (see, e.g., Cowie and Scholz, 1992). For earthquakes, α is typically B1023 to 1024, some 100 times less than for faults. The difference can be understood because earthquakes and their aftershocks are individual slip events, while faults, as observed in the subsurface, represent the cumulative effect of many slip events over geological time. A shear modulus value of μ 5 4 GPa would be typical for undamaged rock in saline aquifer storage formations (the shear modulus for a fault might be half of this value but using 2 GPa would reduce MW by just 0.2). Figure 12.19 also shows MW versus L using this approach, for values of α from 1023 to 1024.

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333

Damaging

5

Faults visible with good to excellent data

α=

4

0 00 00 0,0 1/1 1/1 α=

Perceptible Worrying

Faults invisible on seismic

3 Faults visible on seismic

2

a a a MP MP MP 0.1 10 1.0 = = = Δσ Δσ Δσ

1

Imperceptible

Earthquake magnitude (MW)

6

0 10

1000

100

10,000

Fault length (m)

Figure 12.19 Magnitude versus fault length based on stress relief and offset/length criteria.

As can be seen from the figure, induced seismic events with MW . 3.5 would be related to faults with L . 500 m, which will generally be visible on seismic, while faults with L up to B100 m will not produce perceptible events. The storage site characterization challenge is therefore to identify faults at the limit of detectability on seismic, particularly close to proposed injection locations where the largest pore pressure increase will occur.

Fault zone characteristics The shear stress released in a fault plane movement is proportional to the difference between static and dynamic coefficients of friction on the fault plane. These values will in turn depend on a range of factors including the nature of the damage zone around the fault (particularly the presence of clays) and of the formations on either side of the fault. Modeling studies have shown that a heterogeneous fault damage zone—one in which the permeability, lithology, mechanical properties, etc., vary significantly over the fault plane—is more likely to result in stress release through multiple, small events rather than a single rupture event propagating over a larger area. Although characterization of faults in the vicinity of a planned injection site will be an important aspect of site selection, these fault zone characteristics will be difficult to assess a priori and are more likely to be inferred from microseismic monitoring— yielding information that may then be transferable to other nearby sites.

Impact on geological storage Current indications, both from simulation studies and from the limited operational experience to date, are that well-designed geological storage operations are unlikely to cause significant seismic events (MW . 3). However, the difficulty in determining the parameters that influence these events within a narrow range of uncertainty,

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including the potential for pressure sensitive faults to go unnoticed during site characterization (as observed, e.g., at In Salah and in the Decatur project), means that events up to MW 5 4
5 cannot be ruled out. In some instances seismic activity resulting from fluid injection has been seen to increase with the cumulative injection volume, while in others (e.g., the Paradox Valley Unit) a change in injection pressure/rate significantly reduced activity after the MW 5 4.3 event noted above. Future injection experience, data gathering, and evaluation will help to identify the factors that determine stress relief behavior (i.e., many small or one large event) and how the risk of larger events can be reduced by operational measures. In this situation it will be prudent to take a precautionary, risk-based approach, which would include the technical measures summarized in Table 12.6.

Table 12.6 Precautionary approach to induced seismicity risk management Project phase

Technical measures

Site selection







Storage planning








Storage operations









Evaluate regional data including natural seismicity, stress, and fault characterization data Preference for storage sites with secondary seals, to provide a multi-barrier storage complex Preference for sites remote from urban areas Avoid sites with faults expected to be at risk of reactivation or where there is large uncertainty in fault characterization Collect baseline 3D seismic, microseismic, and in situ stress data Evaluate fault reactivation tendency for observed faults Design injection strategies, including injection ramp-up, based on best in situ stress estimate, fault reactivation tendency, and related uncertainties Plan operational response to seismic events of increasing magnitude (e.g., establish trigger levels and responses, such as reduced injection or production above leaking fault) Plan remediation measures in the event of primary seal leakage due to fault movement Monitor and analyze microseismicity to update subsurface understanding and models Monitor average pressure using falloff surveys Update fault hazard analysis to provide constraints on unknown parameters and calibrate geomechanical models Adjust monitoring plan in response to subsurface observations (e.g., targeting specific areas) Implement planned operational responses as required Share microseismicity data among operators to establish regional database and modeling studies

Geological and geomechanical features, events, and processes

335

Such an approach would progressively develop the body of operational experience in the geological and geomechanical domain that will be required to underpin safe, impact scale deployment. A protocol for addressing induced seismicity associated with enhanced geothermal systems has been issued by the US Department of Energy (see Resources), and similar guidance is under development for carbon storage sites.

12.6

References and resources

12.6.1 References Baker, J.W., 2008. An introduction to probabilistic seismic hazard analysis (PSHA). Unpublished report available from web.stanford.edu/Bbakerjw/Publications/Baker_ (2008)_Intro_to_PSHA_v1_3.pdf. Begg, S.H., P.R. King, 1985. Modeling the effects of shales on reservoir performance: calculation of effective vertical permeability. Society of Petroleum Engineers (SPE 13529). 1985 SPE Reservoir Simulation Symposium, Dallas, TX. Bickle, M., Chadwick, A., Huppert, H.E., Hallworth, M., Lyle, S., 2007. Modelling carbon dioxide accumulation at Sleipner: implications for underground carbon storage. Earth Planet. Sci. Lett. 255, 164
176. Carey, J.W., Frash, L.P., 2017. Brittle-ductile behavior and caprock integrity. Energy Procedia. 114, 3132
3139. Cavanagh, A., Wildgust, N., 2011. Pressurization and brine displacement issues for deep saline formation CO2 storage. Energy Procedia. 4, 4814
4821. Chadwick, R.A., Noy, D., Arts, R., Eiken, O., 2009. Latest time-lapse seismic data from Sleipner yield new insights into CO2 plume development. Energy Procedia. 1, 2103
2110. Cowie, P.A., Scholz, C.H., 1992. Displacement-length scaling relationship for faults: data synthesis and discussion. J. Struct. Geol. 14, 1149
1156. Durucan, S., Shi, J.-Q., Sinayuc, C., Korre, A., 2011. In Salah CO2 storage JIP: carbon dioxide plume extension around KB-502 well—new insights into reservoir behaviour at the In Salah storage site. Energy Procedia. 4, 3379
3385. El-Mowafy, H.Z., Marfurt, K.J., 2016. Quantitative seismic geomorphology of the middle Frio fluvial systems, south Texas, United States. AAPG Bulletin. 100, 537
564. Hillis, R.R., D.N. Dewhurst, S.D. Mildren, R.M. Jones, 2003. Assessing the risk of fault seal breach due to reactivation—a geomechanical approach. EAGE 65th Conference & Exhibition, Stavanger, Norway, 2
5 June 2003. Hovorka, S.D., et al., 2006. Measuring permanence of CO2 storage in saline formations: the Frio experiment. Environ. Geosci. 13, 105
121. Iding, M., Ringrose, P., 2009. Evaluating the impact of fractures on the long-term performance of the In Salah CO2 storage site. Energy Procedia. 1, 2021
2028. Luo, Z., S.L. Bryant, 2010. Influence of thermo-elastic stress on CO2 injection induced fractures during storage. Society of Petroleum Engineers (SPE 139719). 2010 SPE International Conference on CO2 Capture, Storage and Utilization, New Orleans, LA. Nicot, J.-P., Hovorka, S.D., Choi, J.-W., 2009. Investigation of water displacement following large CO2 sequestration operations. Energy Procedia. 1, 4411
4418.

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Preisig, M., Pre´vost, J.H., 2011. Coupled multi-phase thermo-poromechanical effects. Case study: CO2 injection at In Salah, Algeria. Int. J. Greenhouse Gas Control. 5, 1055
1064. Rohmer, J., Bouc, O., 2010. A response surface methodology to address uncertainties in cap rock failure assessment for CO2 geological storage in deep aquifers. Int. J. Greenhouse Gas Control. 4, 198
208. Rutqvist, J., Vasco, D.W., Myer, L., 2010. Coupled reservoir-geomechanical analysis of CO2 injection and ground deformations at In Salah, Algeria. Int. J. Greenhouse Gas Control. 4, 225
230. Streit, J.E., Siggins, A.F., Evans, B.J., 2005. Predicting and monitoring geomechanical effects of CO2 injection. In: Thomas, D.C., Benson, S.M. (Eds.), Carbon Dioxide Capture for Storage in Deep Geological Formations, Vol. 2. Elsevier, Oxford, UK. Warren, J.E., Root, P.J., 1963. The behavior of naturally fractured reservoirs. Soc. Pet. Eng. J. 3 (245
255), (SPE-426-PA). White, J.A., Foxall, W., 2014. A phased approach to induced seismicity risk management. Energy Procedia. 63, 4841
4849. Zoback, M.D., Gorelick, S.M., 2012. Earthquake triggering and large-scale geologic storage of carbon dioxide. Proc. Natl Acad. Sci. USA. 109, 10164
10168.

12.6.2 Resources IEAGHG; Induced seismicity and its implications for CO2 storage risk. Report 2013/09, June 2013. Available at www.ieaghg.org/docs/General_Docs/Reports/2013-09.pdf US DOE EERE; Protocol for addressing induced seismicity associated with enhanced geothermal systems. Report DOE/EE-062, January 2012. Available at http://energy.gov/ eere/geothermal

Fluid properties and rock
fluid interactions

13

The in situ properties of injected CO2 and other fluids present in the host formation and the physical interactions between these fluids and the various rock types are the overriding factors that determine the flow behavior of injected CO2 and the effectiveness of one of the most important trapping mechanisms—residual trapping.

13.1

Fluid properties

13.1.1 CO2 properties Density and compressibility of CO2 The critical point of CO2, at Tc 5 31.1 C and Pc 5 7.38 MPa, is within the range of temperatures and pressures that will be encountered in most geological storage operations, and the density and compressibility will therefore be strongly pressure and temperature dependent in some parts of the system. Table 13.1 shows indicative operating temperatures and pressures for a number of geological storage projects. Figure 13.1 illustrates the density of CO2 as a function of temperature and pressure in the range of interest for storage operations, with points (1) to (5) showing the (T, P) data for the projects in Table 13.1. For typical storage conditions, CO2 density lies in the range 300
700 kg/m3, which compares with typical brine densities (see next section) of 1000
1100 kg/m3. At pressures below 9 MPa and temperatures above 25 C, both density and compressibility vary considerably with T and P. At the extreme, for pressures close to Pc, a 10 C increase in temperature can halve the fluid density. For reservoirs close to the critical point, this will mean that small temperature and pressure uncertainties can have a significant impact on estimated fluid density and therefore on predicted plume behavior and storage capacity. Figure 13.2 shows the compressibility factor (Z) of CO2 at 50 C, in the middle of the range of formation temperatures shown in Table 13.1, where: Z 5 P=ρðP; TÞ RT

(13.1)

Viscosity of CO2 The viscosity of CO2 as a function of pressure is shown in Figure 13.3. In comparison, pure water has a viscosity of 0.55 mPa  s at 50 C and 0.1 MPa increasing by about 1% at 30 MPa. Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00013-1 © 2017 Elsevier Inc. All rights reserved.

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Table 13.1 Reported temperatures and pressures of operating geological storage projects Project and injection point

Depth (m)

T ( C)

Pres (MPa)

Pinj (MPa)

(1) Ketzin—Stuttgart formation (2) Sleipner—Utsira formation (3) Frio—Upper Frio formation (4) In Salah—Krechba formation (5) Snøhvit—Tuba˚en formation

630
650 800
1100 1500
1660 1880
1900 2700

34 41 56 90
95 93
98

7.3 10.3 15.0 17.5
17.9 26.4
28.5

6.5
7.5 B15 15
16.5 28 B35

1000

CO2 density (kg/m3)

Liquid phase

40 MPa

800 2

600 Two-phase region

30

3

Supercritical region

400

5

20 4

15

1

10

200 Gas phase

0 0

20

40

60

80

100

120

Temperature (°C)

Figure 13.1 Density of CO2 as a function of temperature and pressure.

CO2 Compressibility factor, Z

1.0 0.8 T = 122°C 0.6 88°C 0.4

55°C

0.2 0 0

10

20 Pressure (MPa)

Figure 13.2 Compressibility factor (Z) of CO2 at 50 C.

30

40

Fluid properties and rock
fluid interactions

339

CO2 viscosity (mPa·s)

0.12 50°C 0.08

90°C 120°C

0.04

0.00 0

10

20

30

40

50

Pressure (MPa)

Figure 13.3 Viscosity of CO2 as a function of pressure.

CO2 viscosity (mPa·s)

0.12 Supercritical region 50 MPa

Liquid phase

0.08 30 20 3 Two-phase region

0.04

5

15

2

4

10 1 Gas phase

0.00 0

20

40

60

80

100

120

Temperature (°C)

Figure 13.4 Viscosity of CO2 as a function of temperature and pressure.

The rapid variation of viscosity with pressure in the region of Pc has a significant impact on flow behavior, both vertical flow in the injection well and flow within the host formation. The dependence of CO2 viscosity on pressure and temperature over the range of (T, P) relevant to geological storage is shown in Figure 13.4. For the five projects shown, CO2 viscosity at host formation conditions lies in the range of 0.02
0.06 mPa  s, compared to a typical brine viscosity in the range 0.4
0.7 mPa  s (see next section). At the point of injection, at lower temperature and higher pressure, CO2 viscosity would be higher, and for (T, P) close to the critical point this difference could be substantial.

13.1.2 Saline aquifer brine properties Brine density The difference in densities between the initial pore fluid and the injected CO2 under in situ conditions provides the buoyant driving force for vertical movement of the

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Carbon Capture and Storage

20°C 40°C 60°C

Water density (kg/m3)

1020 1000

1

2

80°C

3

100°C

980 5

4

960 150°C

940 920 0

10

20

30

40

50

Pressure (MPa)

1200

1200

1150

1100 Density (kg/m3)

Density (kg/m3)

Figure 13.5 Density of pure water as a function of temperature and pressure.

1.5 MPa 0.25 kgNaCl/kgSolution

1100

1050

150°C 1.5 MPa 1000

900

1000

800 0

50

100

Temperature (°C)

150

0

0.1

0.2

0.3

NaCl mass fraction (kg/kg)

Figure 13.6 Typical dependence of brine density on temperature and salinity.

CO2 plume and an accurate assessment of brine density is therefore an important input to fluid flow simulation. The density of pure water can be determined using the IAPWS97 model (IAPWS, 2007) and is shown in Figure 13.5 for the range of (T, P) relevant to geological storage operations. The density of formation brine depends on the salinity and to a degree on the electrolyte species present. A number of algorithms have been developed to estimate brine densities, for example, by Mao and Duan (2008), where earlier work is also reviewed. Figure 13.6 illustrates the typical dependence of brine density on temperature and salinity (NaCl mass fraction), based on the Mao and Duan model.

Brine viscosity The viscosity of pure water can also be determined, with an uncertainty of c. 1%, from the IAPWS model (IAPWS, 2007—see Resources). A number of algorithms

341

2.0

2.0

1.5

1.5

Viscosity (mPa·s)

Viscosity (mPa·s)

Fluid properties and rock
fluid interactions

1.5 MPa 0.25 kgNaCl/kgSolution

1.0

0.5

0

1.0 150°C 1.5 MPa 0.5

0 0

50

100

150

Temperature (°C)

0

0.1

0.2

0.3

NaCl mass fraction (kg/kg)

Figure 13.7 Typical dependence of brine viscosity on temperature and salinity.

are then available to calculate brine viscosity as a function of temperature, pressure, and salinity, of which that due to Mao and Duan (2009) is the most recent and comprehensive. Figure 13.7 illustrates the typical dependence of brine viscosity on temperature and salinity derived from this model.

13.1.3 Brine
CO2 mutual solubility and solution properties CO2 solubility in formation brine The solubility of CO2 in formation brine will determine the magnitude of solubility trapping and is dependent on the physical conditions of temperature and pressure as well as the ionic strength (salinity) and chemical composition of the formation brine. An assessment of formation brine chemistry (including ionic composition and pH, as well as dissolved organic and inorganic carbon content) will therefore be an aspect of site characterization. Solubility values for CO2 over a range of conditions and in a variety of aqueous solutions have been determined from experimental studies and several theoretical models have been developed to incorporate solubility effects in numerical simulation (see Duan and Sun, 2003; Portier and Rochelle, 2005). Early models developed in the 1980s and 1990s over- or under-predicted experimental data by 10%
20%, but more recently the models of Duan and Sun and of Portier and Rochelle match experimental data within the range of experimental error (5%
10%). The Duan
Sun model has the added advantage that it can be applied to a variety of aqueous solutions (e.g., CaCl2, MgCl2, (NH4)2SO4, and seawater) without the need for experimental data for those solutions to determine model parameters. Figure 13.8 illustrates the dependence of CO2 solubility in pure water and in aqueous NaCl solutions on temperature, pressure, and solution ionic strength, as predicted by this model. CO2 solubility for the five sites noted in Table 13.1 ranges from B0.6 to B1.0 mol/ kg, while the rapid decline in solubility with increasing salinity indicates a preference for host formations with lower salinity, if solubility trapping is to be maximized.

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Carbon Capture and Storage

2.0

2.0

1.5

120°C CO2 solubility (mol/kgwater)

CO2 solubility (mol/kgwater)

10 MPa Pure water 1M

1.0

2M 4M

0.5

1.5

1.0 Pure water

0.5

4M 0

0 0

50

100

150

Temperature (°C)

0

10

20

30

Pressure (MPa)

Figure 13.8 Solubility of CO2 versus T and P in pure water and NaCl solutions (1
4 M).

Water solubility in CO2 In the region around an injection well and for some distance into the host formation, CO2 will become the dominant phase after a period of injection, occupying most of the pore space. As a result of the hydrodynamic behavior discussed below, the water saturation will be progressively reduced to a residual value (Swrc)—reflecting water present in pores that are inaccessible to CO2 and as a wetting film on the grain surfaces in swept pores. In this swept region, further reduction in the water saturation will occur as a result of the dissolution of this residual water into the CO2. Figure 13.9 shows the predicted water solubility in CO2 at various temperatures, based on equation-of-state (EOS) models matched to experimental data by Spycher et al. (2003). The dissolution of residual water into the CO2 will result in drying out of the host formation, the concentration of formation brine leading to precipitation of halite and other minerals in the pore space, the dehydration of clays present either as a pore filling or a structural component, as well as a change in wettability and possibly the mechanical properties of the host formation. As discussed in the following sections, these effects will have an impact on formation permeability, relative permeability, residual CO2 saturation (with consequences for storage capacity and injection rate), and potentially on the sealing capacity of the caprock and of flow barriers within the formation.

Density of aqueous CO2 solutions The density of aqueous CO2 solutions has been measured experimentally over a wide range of conditions, and a number of models have been developed from these data to predict solution densities under varying conditions. Duan and co-workers reviewed the data and previous models and developed an improved model for

Fluid properties and rock
fluid interactions

343

2.5

H2O solubility (mol %)

100°C 2.0 1.5 75°C 1.0 50°C 0.5 25°C 0 0

10

20

30

Pressure (MPa)

Density ratio (ρCO2 seawater/ρseawater)

Figure 13.9 Predicted solubility of water in pure CO2. Source: After Spycher et al. (2003).

1.100 1.008 1.006 1.004 1.002 1.000 0

1

2

3

4

CO2 content (wt%)

Figure 13.10 Density of aqueous CO2 solutions. Source: After Duan et al. (2008).

geological storage relevant conditions (Duan et al., 2008). Figure 13.10 illustrates the increase in seawater density with dissolved mass fraction of CO2, a CO2 content of 4.0 wt% resulting in a B1% increase in density. In host formations with sufficient vertical permeability, buoyancy forces resulting from this increase in brine density will result in a downward movement of CO2-saturated brine and its replacement by unsaturated brine. The convective mixing resulting from this gravity current will enhance solution trapping as it will continually bring unsaturated brine into contact with the remaining free phase CO2.

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Carbon Capture and Storage

13.1.4 Water
CO2 vapor phase properties To maximize storage capacity under normal conditions, injected CO2 will remain in the dense phase (liquid or supercritical fluid) throughout the life of a geological storage project and thereafter during long-term sequestration. However, in order to model leakage at depths shallower than the critical pressure equivalent depth (B730 m under hydrostatic conditions) it will be necessary to describe vapor phase properties in the model. These properties can be conveniently derived using an EOS which has been fitted to experimental data over the (T, P) range of interest in order to determine the interaction parameters. For example, a virial-type EOS of the form shown in Equation (13.2) has been used to fit the experimental data for CO2
H2O mixtures: PVm =RT 5 1 1 B=Vm 1 C=Vm2 1 D=Vm3 1 ?

(13.2)

where Vm is the molar gas volume, and the free parameters B, C, D, . . . are functions of temperature only (see Duan et al., 2008). However, for typical geothermal gradients, saturated gaseous CO2 will contain less than 1 mol% H2O, and the deviation from pure CO2 properties will be at most a few %. For example, the density of the equilibrium mixture at 7.3 MPa and 34 C (Ketzin conditions) exceeds the pure CO2 density by less than 3% (0.266 vs 0.260 kg/m3). Since the other properties of the overburden are likely to be significantly more uncertain, the pure gas properties may be adequate for modeling CO2 behavior above the critical pressure depth.

13.2

Single-phase flow in porous media

The movement of CO2 injected into a saline aquifer is a function of many different features of the rock and fluids present, including fluid properties, absolute and relative permeability, capillary pressure, etc. The starting point to discuss these effects and processes is single-phase fluid flow, as described by Darcy’s equation.

13.2.1 Darcy’s law The flow of water through sand beds was first studied by French engineer Henry Darcy in the 1850s, and the resulting Darcy equation remains the foundation of hydrology and of oil and gas reservoir engineering today. The empirically derived relationship allows the flow rate of a fluid to be determined, as follows: q 5 2 ðkA=μÞΔP=ΔL

(13.3)

where q is the flow rate (m3/s), k is the permeability of the porous medium (m2), A is flow area (m2), μ is the fluid viscosity (kg/m  s or Pa  s), and ΔP is the pressure drop (Pa) over length ΔL (m). ΔP may be due to an imposed driving pressure,

Fluid properties and rock
fluid interactions

345

for example, in the vicinity of an injection well, or to buoyancy force resulting from a difference in density of two fluids (see below). With a knowledge of average formation pressure and permeability and of fluid viscosity, this relationship provides the basis for determining the required bottom hole pressure to achieve a desired rate of CO2 injection or the expected rate of a producing well. Considering the flow of CO2 injected into a vertical well, the profile of pressure around the well is given by: δP=δr 5 qμ=2πkhð1=r
r=re2 Þ

(13.4)

where, in addition to the terms defined above, h is the thickness of the formation into which injection is taking place (m), r is the radial distance from the center of the well (m), and re is the effective radius of an outer no-flow boundary (m). When considering the near wellbore region (r , 50 m) and for a large storage aquifer (re . 1000 m), the term r/re2 can be ignored. It is illustrative to compare this radial pressure gradient with the vertical pressure gradient driving buoyant movement of CO2. The vertical pressure gradient is given by: δP=δl 5 ΔρUg

(13.5)

where Δρ is the density difference between aquifer brine and CO2 (kg/m3), and g is the acceleration due to gravity (m/s2). Table 13.2 compares these two pressure gradients for reservoir and fluid parameters representative of the Utsira aquifer at Sleipner and shows that, for r .B5 m, the buoyant gradient exceeds the radial pressure gradient from the well.

13.3

Wettability, capillary pressure, and relative permeability

Three characteristics of rock
fluid interactions—namely, wettability, capillary pressure, and relative permeability—are the features that control the processes of drainage and imbibition that occur when CO2 is injected into and migrates through a storage formation. Together with the geological features described in the previous chapter, these features play a major part in determining storage capacity.

13.3.1 Wettability, contact angle, and interfacial tension When two fluids such as CO2 and water are present in the pore space of a porous medium, one of the fluids will preferentially wet the rock and will tend to cover the grain surfaces while the other will preferentially occupy the open pore space. Which of the two fluids is the wetting phase depends on the relative interfacial tensions (IFTs) between the fluids and the grain surface. A simple way of visualizing

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Carbon Capture and Storage

Table 13.2 Radial and vertical pressure gradients for Sleipner conditions Parameter

Value

CO2 injection rate CO2 density Brine density CO2 viscosity Aquifer permeability Aquifer permeability to CO2 Injection zone thickness Radial distance Radial pressure gradient Buoyant pressure gradient

SI units

0.062 515 1020 0.00004 2.5 3 10212 0.5 3 10212 30 5.3 4930 4950

3

m /s kg/m3 kg/m3 Pa  s m2 m2 m m Pa/m Pa/m

Value

Conventional units

1

Mt-CO2/year

0.04 2500 500

cP (centipoise) mD (millidarcy) mD

Gas (g)

Liquid (l) Solid (S)

γgl

θ γls

Wetting phase

θ γgs

γls

γgl γgs

Non-wetting phase

Figure 13.11 Wettability demonstrated by difference in contact angle.

this is to consider the two fluids separately in contact with a grain-like surface (e.g., glass in place of silica grains), as shown in Figure 13.11, where the fluid on the left, with the lower contact angle (θ), will be the wetting phase when the two fluids share the pore space. The contact angle is related to the IFTs between the grain surface and the two fluids according to Young’s equation: γ rc 2 γ rb 5 γ bc cos θ

(13.6)

where γ rb, γ rc, and γ bc are the rock
brine, rock
CO2, and brine
CO2 IFTs. The wetting phase is said to be more strongly wetting as the contact angle decreases. An intermediate (also known as mixed) wetting condition occurs if the contact angle is close to 90 degrees, so that neither fluid strongly wets the grain surfaces or, less commonly, if due to mineralogical differences some grains are preferentially wet by one fluid and some by the other.

Fluid properties and rock
fluid interactions

Imbibition: wetting phase advancing Increased contact angle

347

CO2

Brine

Drainage: wetting phase receding Reduced contact angle

Grain surface

Figure 13.12 Brine
CO2 contact angle hysteresis under drainage and imbibition.

The fraction of the pore space occupied by water is termed the water saturation (Sw) and similarly for any other fluid present, the sum of all fluid saturations (e.g., Sw 1 SCO2) being equal to one. Conventionally, a flow process causing an increase in the wetting phase saturation—such as the waterflooding of a water-wet oil reservoir—is termed imbibition, while a process that reduces the wetting phase saturation is termed drainage. Thus, injection of CO2 into an aquifer (wetting phase saturation decreasing) is a drainage process, while the process that occurs after the cessation of CO2 injection, where water flows into the pore space behind a rising buoyant plume, is an imbibition process. Under dynamic conditions, the contact angle varies depending on the direction of fluid flow. This is illustrated in Figure 13.12, which shows schematically the contact surface between brine, CO2, and a rock grain under imbibition (brine advancing), drainage (brine receding), and under static conditions. Under imbibition the contact angle increases, indicating less water wet conditions, while under drainage the reverse is true, a smaller contact angle indicating more strongly water wet conditions. This behavior—known as hysteresis—has important implications for both capillary pressure and relative permeability, as discussed below. In aquifers (water-wet), brine
CO2 IFT is strongly dependent on pressure, temperature, and brine salinity, as illustrated in Figure 13.13 (see Bachu and Bennion, 2009). Since IFT directly impacts on capillary pressure and relative permeability it will be important to establish these parameters for conditions that are representative of the host formation. For intermediate or oil-wet rocks, which may occur in depleted oil reservoirs, as well as for shaly caprocks, experimental core flooding investigations have shown that injected CO2 can become the wetting phase (see Chiquet et al., 2005; Chalbaud et al., 2010). As discussed in the next section, this would reduce the threshold capillary pressure for CO2 to enter the pores of the caprock, increasing the potential for geochemical alteration. Within the reservoir, if CO2 wets the grain surfaces, smaller pores will be infiltrated during injection, increasing the maximum CO2 saturation achieved which, as discussed below, will increase storage capacity as a result of increased residual trapping.

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Carbon Capture and Storage

80

80

Temp (°C) 125

60 75

IFT (mN/m)

IFT (mN/m)

60 40

40

20

NaCl (wt%) 30 15 0

40

20

0

0 0

10

20

30

0

Pressure (MPa)

10

20

30

Pressure (MPa)

Figure 13.13 Brine
CO2 IFT dependence on pressure, temperature, and brine salinity.

Capillary pressure (kPa)

Low irreducible saturation

High irreducible saturation

Low permeability Wide pore size distribution

High permeability Narrow pore size distribution 0

0.2

High entry pressure

Low entry pressure

0.5

0.75

1

Wetting phase saturation (Sw)

Figure 13.14 Schematic capillary pressure curves.

13.3.2 Capillary pressure and capillary trapping The capillary entry pressure (Pce) is the threshold pressure required to force the non-wetting fluid through a pore throat of radius r. This is a function of the contact angle and IFT between the two fluids (here γ bc, assuming brine (subscript b) to be wetting and CO2 (subscript c) to be non-wetting) and is given by: Pce 5 2γ bc cos θ=r

(13.7)

A typical rock sample will be characterized by a distribution of grain sizes, and therefore also of pore throat radii, and each pore throat will have an entry pressure defined by Equation (13.7). When the non-wetting phase is forced into the rock at a given pressure (P), only those pores accessible through pore throats with radii greater than 2γ bccos θ/P will be infiltrated. This is illustrated schematically in Figure 13.14, which shows the so-called capillary pressure curve for a sample,

Fluid properties and rock
fluid interactions

Capillary pressure (kPa)

+

349

Irreducible saturation

Drainage Spontaneous imbibition 0 Forced imbibition Residual saturation

– 0

Wetting phase saturation (Sw)

1

Figure 13.15 Schematic drainage
imbibition capillary pressure curves.

measuring the non-wetting phase saturation achieved as a function of the applied pressure. Two generic rock types are illustrated: a well sorted large grained rock, which will display high porosity and permeability, and a poorly sorted, finer grained rock which will have lower porosity and permeability. The high permeability sample has a low entry pressure and a flat capillary pressure curve reflecting the majority of pores being infiltrated over a narrow pressure range. In contrast, the low permeability sample has a high entry pressure followed by a steep curve, reflecting the wide distribution of pore and pore throat sizes. The curves illustrated in Figure 13.14 are drainage capillary pressure curves, since they represent a process in which the wetting phase saturation is reducing. If the direction of saturation change is reversed, i.e., from drainage to imbibition, a different curve will be traced due to the phenomenon of contact angle hysteresis noted above. Figure 13.15 shows typical schematic drainage
imbibition capillary pressure curves which, generically, represent the process of CO2 infiltration into an aquifer followed by water imbibition in the wake of the migrating plume. With the removal of the pressure forcing infiltration of the non-wetting phase, the wetting phase will spontaneously imbibe into the rock to a degree, reducing the non-wetting phase saturation (Snw) to an intermediate value. Further reduction of Snw, termed forced imbibition, requires an excess pressure to be applied to the wetting phase (hence a negative capillary pressure following the usual sign convention). The caprock in a hydrocarbon reservoir relies on capillary pressure— specifically a very high entry pressure for the non-wetting phase—to function as a seal, and the same will be true for structural trapping in a geological storage

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Carbon Capture and Storage

Permeable storage formation

Low permeability flow barrier

Capillary trapped CO2 Residual trapped CO2

Figure 13.16 Capillary trapping below a low permeability flow barrier.

situation. As the thickness of the buoyant column trapped below a seal increases, the excess pressure of the non-wetting phase (Pnw) at the top of the column increases according to: Pnw
Pw 5 Δρgh

(13.8)

where g is the acceleration due to gravity (m2/s), h is the thickness of the buoyant column (m), and Δρ is the density difference between the two fluids (kg/m3). Thus for a caprock characterized by an entry pressure Pce, the maximum column height to prevent capillary entry of the non-wetting phase is given by: hmax 5 Pce =Δρg

(13.9)

or using Equation (13.7), hmax 5 2γ bc cos θ=Δρgr

(13.10)

The natural heterogeneity of permeability, and therefore of capillary entry pressure, in a geological storage formation can result in buoyant CO2 being trapped below low permeability layers due to capillary forces (see Saadatpoor et al., 2008). This capillary trapping, illustrated in Figure 13.16, can occur from the centimeter to meter scale, for localized features such as clay drapes, up to hundreds of meters or larger. A large-scale example has been observed in the Utsira aquifer at Sleipner, where CO2 pools below nine mudstone layers were estimated to account for roughly 2/3 of injected CO2 after 10 years of injection (Hermanrud et al., 2009). In the longer term, once injection ceases, up to half of this ponded volume will remain residually trapped below the mudstone layers, while part of the remainder may be retained through capillary trapping. The extent of capillary trapping is highly uncertain, being entirely dependent on the geometry of the flow baffles

Fluid properties and rock
fluid interactions

351

Relative permeability (Fraction)

1.0 Brine end-point permeability 0.8 Brine 0.6 CO2 end-point relative permeability

0.4 CO2

0.2

Irreducible brine saturation 0 0

0.2

0.5

0.75

1

CO2 saturation (Fraction)

Figure 13.17 Generic two-phase CO2
brine relative permeability curves.

which are below the resolution of seismic surveys. Such baffles will be observable in cores or well logs, but this gives sparse areal sampling, and only provides clues as to their geometry. Capillary trapping may also be reduced to zero if wettability changes occurred in the flow barriers after long contact with CO2, i.e., if the fine grained sediments became intermediate wet, since this would reduce the capillary entry pressure to near zero (Equation (13.7) as θ approaches 90 degrees). The mobilized CO2 would then infiltrate the rock above the baffle and would there be subject to further residual trapping before reaching the caprock.

13.3.3 Relative permeability and residual trapping When two fluids occupy the pore space the ability of each phase to flow will generally depend on the relative proportions, or saturation, of the two phases. This dependency is expressed as a saturation-dependent permeability, or relative permeability, as illustrated for a CO2
brine system in Figure 13.17. The end-point for the brine curve at zero CO2 saturation represents the singlephase brine permeability of the rock, while the end-point for the CO2 curve is reached when the brine saturation is reduced to its lowest possible level—the residual brine saturation. Experimentally measured values for the CO2 end-point relative permeability in potential storage formation range from 0.1 to 0.6, while residual brine saturations range from 0.3 to 0.6 (i.e., maximum CO2 saturation of 0.4
0.7). The degree of curvature of the relative permeability curves is a measure of the degree to which the presence of one fluid inhibits the flow of the other fluid, the

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more concave the curves the greater the interference. Conversely, straight-line relative permeability lines, shown dotted in the figure, would be applicable if there were no interaction, for example, in the case of segregated flow in a very high permeability or vertically fractured reservoir or for fully miscible flow of two fluids.

Fluid mobility and flood front stability Within a rock volume at a given wetting phase saturation, the flow of each phase will be governed by the Darcy equation. Thus, for phase 1: q1 5 2ðkUkr1 A=μ1 ÞΔP1 =ΔL

(13.11)

where k is the absolute permeability and kr1 is the relative permeability to phase 1 at the given saturation condition. The term k  kr1/μ1 is called the mobility of phase 1. Neglecting capillary pressure effects (so that P1 5 P2), the flow rates of the two phases are in the ratio: q1 =q2 5 kr1 μ2 =kr2 μ1

(13.12)

which is equal to the ratio of the phase mobilities (commonly denoted M, with phase 1 being the displacing fluid). Thus, in the saturation range where both phases are flowing, the fluid with the higher mobility will move more rapidly through the formation. In the case of CO2 injection into an aquifer, CO2 will be the more mobile fluid due to its lower viscosity. The consequence of this is that for CO2 injection into an aquifer (with M greater than 1) some parts of the formation may be bypassed by the CO2 plume, reducing residual trapping effectiveness. In oilfield practice this flood front instability occurs when waterflooding reservoirs with higher oil viscosity, and is addressed by the strategy of mobility control, which involves modifying the viscosity of one or other fluid, for example, increasing the water viscosity by the co-injection of polymers or reducing the oil viscosity by heating in thermal EOR. For geological storage, one option for mobility control is to inject CO2 as a CO2
brine mixture, and this has been proposed to accelerate residual and solubility trapping (see Chapter 17; Qi et al., 2009). Figure 13.18 shows the mobility ratio between a CO2
brine mixture and a formation brine as the CO2 fraction (fCO2) in the mix varies. Over a wide range of fCO2 the mobility ratio is less than 1 and the flood front is therefore stable. The figure also shows the mobility ratio curve for a later injection of chase brine, to further accelerate trapping.

Imbibition and drainage processes The relative permeability curves shown in Figure 13.17 represent a drainage process with water being displaced by CO2 in a water wet rock. However, the hysteresis

Fluid properties and rock
fluid interactions

353

Mobility ratio

10 Mobility ratio of CO2–brine mixture to formation brine

Unstable flood 1 Stable flood

Mobility ratio of chase brine to original CO2–brine mixture

0.1 0

0.2

0.5

0.75

1

Injected fluid CO2 volume fraction

Figure 13.18 Mobility ratio of an injected CO2
brine mixture to formation brine. Source: After Qi et al. (2009).

Relative permeability (Fraction)

1.0 Drainage 0.8 Imbibition

Brine 0.6 Brine end-point relative permeability

0.4

CO2

0.2 Residual CO2 saturation 0 0

0.2

0.5 0.75 CO2 saturation (Fraction)

1

Figure 13.19 Relative permeability hysteresis for CO2 injection into an aquifer.

described in the discussion on capillary pressure also affects relative permeability and, whenever there is a reversal in the direction of flow, hysteresis effects will occur. Figure 13.19 shows an example of relative permeability hysteresis in a brine
CO2 system with a drainage process (same curves as Figure 13.17) representing increasing CO2 saturation at the leading edge of a migrating plume, followed by an imbibition process (as brine displaces CO2 in the wake of the plume). As for capillary pressure, hysteresis in relative permeability occurs as a result of the dependence of the contact angle on the direction of the saturation change and second, during imbibition, as a result of the trapping within the pores of the

Carbon Capture and Storage

Relative permeability (Fraction)

354

0.4 Sc,max 0.3 Sci 0.2 CO2 0.1 Sct,(Sci)

Sct,max

0 0

0.2

0.5

0.75

1

CO2 saturation (Fraction)

Figure 13.20 CO2 relative permeability curve showing saturation-dependent trapping.

receding phase (here CO2). These generic curves show that, as the saturation of the receding phase reduces, a point is reached at which the relative permeability for that phase becomes essentially zero. The saturation at this point is called the irreducible saturation (Swirr) in the case of brine, or the residual saturation (Scr) in the case of CO2. This is the process that results in residual trapping of CO2 during geological storage. Although Figure 13.19 shows a lower brine relative permeability during imbibition than drainage for a given CO2 saturation, there are also examples where this is reversed—where the impact of CO2 in reducing brine permeability is less when the CO2 saturation is decreasing than when it is increasing. In general, the higher the non-wetting phase saturation that is reached in a drainage process, the higher the residual saturation that will be left after the subsequent imbibition. This is illustrated in Figure 13.20, which shows how the non-wetting phase curve during imbibition depends on the saturation reached at the end of the drainage cycle. A number of empirical relationships, known as trapping models, have been derived to determine the residual or trapped saturation (labeled Sct in the figure) as a function of this initial saturation (Sci) (see Spiteri et al., 2005). Residual trapping operates on the timescale of plume migration and is the primary trapping mechanism that occurs before the plume reaches the cap rock of the storage formation. Quantification of the residual CO2 saturation, through experimental measurement of relative permeability under in situ conditions or, increasingly, through pore-scale modeling, is an essential input to performance monitoring and capacity estimation. Reservoir scale assessment can also be achieved by pilot testing, as shown in Figure 13.21. In this example, from the Frio brine pilot, the results of CO2 saturation logging in the observation well (located 30 m away from the injection point) clearly shows the decline in CO2 saturation toward a residual value as brine imbibition occurs behind the plume, following the 10 day injection period. The imbibition process is enhanced here by the relatively steep dip of the formation (11
16 degrees) which results in rapid updip migration of the plume.

Fluid properties and rock
fluid interactions

Day 4

Day 10

Day 29

Day 66

5020

5030

Frio C sandstone

5040

Saturation increasing during drainage

Saturation decreasing during imbibition

Day 142 CO2 saturation and pressure

Perforations

Depth (ft) 5010

355

5050

0

1

0

1 0

1 0

1 0

1 0

1

CO2 saturation (Fraction)

Shale fraction

Figure 13.21 CO2 saturation logging at the Frio Brine Pilot observation well. Source: After Hovorka et al. (2006).

Two-phase flow

CO2 saturation and pressure

Single-phase CO2 flow in dry zone Single-phase brine flow

CO2 saturation Pressure

rw

rdry

rfront

re

Radial distance from well

Figure 13.22 Flow regions around an injection well; schematic radial profiles of pressure and saturation.

The dependence of CO2 trapping on the maximum saturation reached during drainage is also demonstrated by these results; at 5023 ft a peak CO2 saturation in excess of 0.8 was reached leaving a residual (trapped) saturation of . 0.3, while in the interval from 5030 to 5033 ft the peak CO2 saturation was only 0.2 and trapped saturation was essentially zero.

Radial flow around an injection well After a period of injection, three distinct flow regions will develop in the zone around an injection well, as illustrated in Figure 13.22. Closest to the well, within

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Carbon Capture and Storage

the radius rdry, two-phase flow will have initially swept the formation brine down to its irreducible saturation and this residual brine will have been removed by dissolution into CO2. In this dry zone CO2 will occupy 100% of the pore space, although this pore space may have been reduced from its initial value as a result of salt precipitation (see below). In the next region, between rdry and rfront two-phase flow of both CO2-saturated brine and brine-saturated CO2 will take place, according to the relative permeability of the two phases. Furthest from the wellbore, at a distance greater than rfront, single-phase flow of brine will take place in response to the pressure gradient from the injection well.

Formation drying effects Formation drying, resulting from the solubility of residual water in injected CO2, results in the precipitation of evaporite minerals such as halite (NaCl), anhydrite/ gypsum (CaSO4), sylvite (KCl), and carnallite (KMgCl3  6H2O) which, even in small quantities, may lead to significant permeability reduction and injectivity loss through the blocking of pore throats. Experimental studies using a clean Berea sandstone have shown a 74% reduction in scCO2 permeability in the dried zone where halite precipitation was observed (see Wang et al., 2010). A commonly used model to predict permeability reduction due to halite deposition is the “tubes-in-series” model (Verma and Pruess, 1988), in which permeability (k) at porosity (Φ) is given by:
n k 5 k0 ðΦ
Φc Þ=ðΦ0
Φc Þ

(13.13)

where Φ0 and k0 are the initial porosity and permeability and Φc is the value of porosity at which permeability is reduced to zero. While evaporite precipitation has typically been highlighted as a risk to injectivity in formations with high formation brine salinity, modeling studies have also demonstrated that this may occur even at relatively low formation brine salinity due to the capillary pressure driven countercurrent imbibition of brine back toward the near wellbore region (see Preuss and Mu¨ller, 2009). More recent studies by Ott et al. (2015) have shown that the distribution of precipitates within the pore space, and therefore the impact on permeability, is flow rate dependent and that at low flow rates drying and halite precipitation can enhance scCO2 permeability. Although negative effects due to formation drying have not been observed in geological storage projects to date, halite deposition and permeability reduction have been observed in hydrocarbon gas producing and storage reservoirs. Periodic injection of freshwater has been found to be an effective treatment in those cases, and the injection of a suitable pre-flush ahead of CO2 injection would be an effective mitigation measure in a geological storage context. In clean formations where there is no risk of clay swelling, a freshwater pre-flush could be used, and such a treatment might need to be repeated periodically if there was a risk of countercurrent brine imbibition back toward the wellbore. At the Ketzin testing site the very high salinity formation brine (235 kg/m3) was displaced from the near wellbore

Fluid properties and rock
fluid interactions

357

Schematic convective mixing cells showing streamlines … sinking CO2 rich brine … rising CO2 lean brine

Figure 13.23 Convective mixing process leading to solubility trapping. Source: After Ennis-King and Paterson (2005).

region by injecting a 30 m3 pre-flush containing a 6% potassium chloride (KCl) solution, followed by various tracers that were injected as part of the monitoring program. Here KCl was used rather than a freshwater because of the need to inhibit clay swelling.

13.3.4 Convective mixing and solubility trapping As noted in Chapter 1, dissolution of CO2 in formation brine (solubility trapping) becomes the dominant trapping mechanism on the millennial timescale. Dissolution of residually trapped CO2 will occur throughout the rock volume traced by the migrating plume, while dissolution of structurally trapped CO2 will take place at the base of the trapped accumulation. Dissolved CO2 will gradually disperse throughout the whole accessible volume by the two processes of diffusion and convection. Diffusion is a very slow process, driven by Brownian motion and the concentration difference between CO2 saturated and unsaturated formation brine, while convection, driven by gravity and the brine density increase resulting from CO2 dissolution (illustrated schematically in Figure 13.23), will be several orders of magnitude faster, depending on the formation characteristics. In particular the vertical permeability of the formation will have a major influence on the speed of convective mixing as can be seen from the gravitational term in Darcy’s equation: qv 5 2ðkv A=μÞΔρg

(13.14)

where qv is the vertical volume flow rate and kv is the vertical permeability. Simulation results, shown in Figure 13.24, demonstrate that a 10-fold increase in kv increases the rate of CO2 dissolution by a similar factor. The onset of convective mixing arises from small-scale variability in brine density, and this will be affected by geochemical processes which consume dissolved CO2.

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Carbon Capture and Storage

Dissolved fraction of CO2

0.20 kv/kh = 1.0

0.1

0.01

0.15

0.10 10

100

1000

10,000

Time (years)

Figure 13.24 Impact of vertical permeability on rate of solubility trapping. Source: After Ennis-King and Paterson (2005).

Table 13.3 Typical impurity levels in captured CO2 stream Capture process

Impurities (. 0.1 vol%)

Impurities (.100 ppm)

Impurities (,100 ppm)

Pre-combustion

H2,a N2, Ar

CO, H2S, CH4, H2O,a CH3OHa O2, N2, H2O H2O, NOx

H2,a H2O

Post-combustion Oxyfuel O2, N2, Ar a

NOx, SOx, CO, NH3 SOx, CO

Indicates dependence on specific process.

This would necessitate coupled fluid dynamic and geochemical modeling, should these processes need to be investigated in detail.

13.4

Impact of impurities on rock and fluid-flow FEPs

The composition of the CO2 injection stream will depend on the particular capture process, as indicated in Table 13.3, which shows typical impurities for the three main processes. The presence of impurities can have a wide-ranging impact on geological storage, affecting features and processes from the physical properties of the injected CO2 to the geochemical processes that influence very long-term storage performance. Those effects related to fluid and rock physical properties and interactions are considered in this section.

Fluid properties and rock
fluid interactions

359

Table 13.4 Critical point values for typical CO2 stream impurities Component

Critical temperature (Tc,  C)

Critical pressure (Pc, MPa)

Nitrogen CO Argon Oxygen CO2 N2O H2S SO2 NO2

2146.9 2140.3 2122.3 2119.6 31.1 36.4 100.0 157.6 157.8

3.40 3.50 4.90 5.04 7.38 7.25 8.94 7.88 10.13

13.4.1 Impact of impurities on CO2 properties The most significant CO2 properties that are affected by the presence of impurities include the phase behavior, density, and viscosity.

Impact on CO2 phase behavior As shown in Table 13.4, typical impurities such as nitrogen, oxygen, and argon will not condense at temperatures of relevance for the geological storage system, due to their very low critical temperatures. The presence of these non-condensable impurities reduces the critical point temperature (Tc) and increases the critical point pressure (Pc) compared to a pure CO2 stream. This is shown in Figure 13.25 for a stream containing 85% CO2 and B5% each of N2, O2, and Ar, as might be present from a low-purity oxyfuel capture process. This is the least pure of a number of capture streams used in the IEAGHG assessment and is used here to show the extremes of potential impurity impact. Higher purity capture streams would fall within the bounds shown in Figures 13.25
13.27. One consequence of this would be the requirement to increase the operating pressure for pipeline transport to avoid two-phase flow. In the example shown, at 20 C a minimum pressure of B10 MPa would be required compared to B6 MPa for pure CO2.

Impact on CO2 density and viscosity The presence of non-condensable impurities reduces both the density and the viscosity of the mixture compared to pure CO2, as can be seen in Figure 13.26 for the same 85% CO2 injection stream considered above.

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Carbon Capture and Storage

85% CO2 supercritical fluid

Liquid

10 Pressure (Mpa)

Bubble point line

Pc

Oxyfuel captured 85% CO2 phase envelope

5

Dew

Tc

Pure CO2 supercritical fluid

30.98°C CO2 7.38 MPa critical point

ne int li

po

Vapor

0 0

10

20 Temperature (°C)

40

30

Figure 13.25 Phase behavior of pure and 85% purity CO2. Source: After IEAGHG (2011).

1.0

Viscosity (mPa·s)

Density (kg/m3)

1000

Pure CO2 500 85% CO2 +Ar/N2/O2

0

Pure CO2 0.5 85% CO2 +Ar/N2/O2

0 0

10

20

30

0

Pressure (MPa)

10

20

30

Pressure (MPa)

Figure 13.26 Density and viscosity of pure and 85% purity CO2. Source: After IEAGHG (2011).

13.4.2 Impact of impurities on geological storage The impact on fluid flow, trapping, and leakage mechanisms as a result of the changes in physical properties and phase behavior of the injected stream are discussed in this section. Impurities can also have an impact on the geochemical reactions taking place within the storage complex, including the caprock, with potential impacts both on the host formation and the caprock. These geochemical aspects are dealt with in the next chapter.

Fluid properties and rock
fluid interactions

361

CO2 + 2.9% SO2 Pure CO2

Normalized structural trapping capacity (CO2 mass)

1.0

Pc

85% CO2 +Ar/N2/O2

15% volume reduction

Pc

0.5

0 0

10

20

30

Pressure (MPa)

Figure 13.27 Impact of impurities on normalized trapping capacity. Source: After IEAGHG (2011).

Impact on fluid flow For single-phase fluid flow, governed by Darcy’s Law (Equation (13.3)), the volumetric flow rate (q) will be increased for a given injection pressure if noncondensable impurities (e.g., Ar, N2, O2) are present, as a result of the reduction in viscosity. However, when converted to a mass flow rate (q 3 ρ), the corresponding reduction in density will counteract the volumetric rate increase. In the case of two-phase flow, the impact of impurities on relative permeability, largely through IFT, will be a further complicating factor. Site-specific relative permeability measurements under in situ conditions using an injected fluid of appropriate composition will be needed to quantify the net result of these competing effects. Remote from the injection well, reduced viscosity and greater buoyancy will accelerate vertical plume movement, resulting in more rapid immobilization beneath a structural trap. However, these same factors will reduce lateral plume extent and consequently the total swept volume within which residual trapping takes place.

Impact on storage capacity With impurities present in the injected stream, the mass of CO2 that can be stored in a structural trap of a given volume will be reduced both as a result of the reduced density of the stream and also because of the fractional volume taken up by the

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Carbon Capture and Storage

impurities. This effect is shown in Figure 13.27, for the 85% CO2 oxyfuel capture stream considered above and for a formation temperature of 58 C. The reduction in storage capacity in this instance can be as much as 40% compared to a pure CO2 stream, for storage at pressures of 12
13 MPa, equivalent to depths of 1200
1300 m under hydrostatic pressure. This loss of structural trapping capacity due to impurities diminishes at greater depths as the formation temperature rises significantly above the critical temperatures, converging toward the simple mass fraction reduction. Also shown in the figure is the normalized capacity for a stream containing 2.9% SO2. In this case the storage capacity would be increased, by up to 5%, as a result of the higher overall density of the contaminated stream. A similar effect will be seen in residual trapping efficiency, since the mass fraction of CO2 trapped in each pore will also be reduced, and this will be compounded by the reduction in the total swept volume noted above. However, a complicating factor will be the impact of impurities on the CO2
brine IFT (γ bc) and capillary entry pressure (Pce) for a given pore throat diameter (see Equation (13.7)). The limited available data indicate that γ bc, and therefore capillary entry pressure, is increased by the presence of non-condensable, non-polar contaminants but reduced by condensable impurities such as SO2. During the initial sweep of a brine-filled rock by the buoyant plume, higher buoyancy forces due to reduced density will be aided or impeded by the change in Pce for a given pore size, and the balance between these two effects will determine whether the maximum CO2 saturation reached is increased or decreased by the presence of impurities. Rock- and fluidspecific measurements under in situ conditions of IFT, capillary pressure, and relative permeability for both drainage and imbibition processes will be required to quantify these competing effects.

Impact on leakage The impact of impurities on IFT and capillary entry pressure will also influence caprock sealing capacity. The few experimental investigations indicate that IFT, Pce, and consequently caprock sealing capacity may be increased by some impurities, but decreased by others, such as SO2, which would aid CO2 migration into the caprock, with potential implications for geochemical alteration and/or leakage. This is an active research area with the aim of developing a robust predictive framework based on extensive experimental data; meanwhile, site-specific measurements will be needed to confirm sealing capacity in the presence of impurities. Any increase in the critical point pressure, as shown for example in Figure 13.26 for the 85% CO2 stream, would result in rising supercritical CO2 becoming gaseous at greater depth (e.g., at B1000 m under hydrostatic conditions in this example vs B800 m for pure CO2). This would affect the minimum formation depth for supercritical storage as well as the point in the overburden at which any leaking CO2 would become gaseous, increasing its mobility and the potential for leakage to surface.

Fluid properties and rock
fluid interactions

13.5

363

References and resources

13.5.1 References Andre, L., Audigane, P., Azaroual, M., Menjoz, A., 2007. Numerical modeling of fluid
rock chemical interactions at the supercritical CO2
liquid interface during CO2 injection into a carbonate reservoir, the Dogger aquifer (Paris Basin, France). Energy Convers. Manage. 48, 1782
1797. Bachu, S., Bennion, D.B., 2009. Dependence of CO2-brine interfacial tension on aquifer pressure, temperature and water salinity. Energy Procedia. 1, 3157
3164. Begg, S.H., Carter, R.R., Dranfield, P., 1989. Assigning effective values to simulator gridblock parameters for heterogeneous reservoirs. SPE Reservoir Eng. 4, 455
463. CO2 Capture Project, 2012. CO2 stream impurities: impacts on geological storage performance and assurance. Phase 1—Reservoir Simulation. CCP Project. Available at www. co2captureproject.org/reports.html. Chalbaud, C., Robin, M., Lombard, J.-M., Bertin, H., Egermann, P., 2010. Brine/CO2 interfacial properties and effects on CO2 storage in deep saline aquifers. Oil Gas Sci. Technol. Rev. IFP. 65, 541
555. Chiquet, P., D. Broseta, S. Thibeau, 2005. Capillary Alteration of shaly caprock by carbon dioxide. Society of Petroleum Engineers (SPE 94183), 2005 SPE Europec/EAGE Annual Conference, Madrid, Spain. Duan, Z., Sun, R., 2003. An improved model calculating CO2 solubility in pure water and aqueous NaCl solutions from 273 to 533 K and from 0 to 2000 bar. Chem. Geol. 192, 257
271. Duan, Z., Hu, J., Li, D., Mao, S., 2008. Densities of the CO2
H2O and CO2
H2O
NaCl systems up to 647 K and 100 MPa. Energy Fuels 22, 1666
1674. Ennis-King, J., Paterson, L., 2005. Role of convective mixing in the long-term storage of carbon dioxide in deep saline formations. SPE J. 10, 349
356 (SPE 84344). Hassanzadeh, H., Pooladi-Darvish, M., Elsharkawy, A.M., Keith, D.W., Leonenko, Y., 2008. Predicting PVT data for CO2-brine mixtures for black-oil simulation of CO2 geological storage. Int. J. Greenhouse Gas Control. 2, 65
77. Hermanrud, C., et al., 2009. Storage of CO2 in saline aquifers—lessons learned from 10 years of injection into the Utsira formation in the Sleipner area. Energy Procedia. 1, 1997
2004. Hovorka, S.D., et al., 2006. Measuring permanence of CO2 storage in saline formations: the Frio experiment. Environ. Geosci. 13, 105
121. IEAGHG (International Energy Agency, Greenhouse Gas R&D Programme), 2011. Effects of impurities on geological storage of CO2. IEA GHG Report 2011/04. IEA Environmental Projects, Cheltenham, UK. King, M.B., Mubarak, A., Kim, J.D., Bott, T.R., 1992. The mutual solubilities of water with supercritical and liquid carbon dioxide. J. Supercrit. Fluids 5, 296
302. Kwon, C.H., Lee, C.-H., Kang, J.W., 2011. Calculation of phase equilibrium for water 1 carbon dioxide system using nonrandom lattice fluid equation of state. Korean J. Chem. Eng. 27, 278
283. MacMinn, C.W., Juanes, R., 2009. A mathematical model of the footprint of the CO2 plume during and after injection in deep saline aquifer systems. Energy Procedia. 1, 3429
3436. Mao, S., Duan, Z., 2008. The p, v, T, x properties of binary aqueous chloride solutions up to T 5 573K and 100 MPa. J. Chem. Thermodyn. 40, 1046
1063.

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Mao, S., Duan, Z., 2009. The viscosity of aqueous alkali-chloride solutions up to 623 K, 1,000 bar, and high ionic strength. Int. J. Thermophys. 30, 1510
1523. Morrow, N.R., 1975. The effects of surface roughness on contact angle with special reference to petroleum recovery. J. Can. Pet. Technol. 14, 42
53. Ott, H., Roels, S.M., De Kloe, K., 2015. Salt precipitation due to supercritical gas injection: I. Capillary-driven flow in unimodal sandstone. Int. J. Greenhouse Gas Control. 43, 247
255. Portier, S., Rochelle, C., 2005. Modelling CO2 solubility in pure water and NaCl-type waters from 0 to 300 C and from 1 to 300 bar. Application to the Utsira Formation at Sleipner. Chem. Geol. 217, 187
199. Pruess, K., N. Mu¨ller, 2009. Formation dry-out from CO2 injection into saline aquifers: Part 1, Effects of solids precipitation and their mitigation. Lawrence Berkeley National Laboratory. Available at http://escholarship.org/uc/item/9p44q7x3. Qi, R., LaForce, T.C., Blunt, M.J., 2009. Design of carbon dioxide storage in aquifers. Int. J. Greenhouse Gas Control. 3, 195
205. Reynolds, C., Krevor, S., (2017). Capillary limited flow behaviour of CO2 in target storage reservoirs in the UK. Energy Procedia. Saadatpoor, E., Bryant, S.L., Sepehrnoori, K. 2008. Effect of heterogeneous capillary pressure on buoyancy-driven CO2 migration. 2008 DPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers (SPE 113984), Tulsa, OK. Smith, S.A., et al., 2017. Relative permeability of Williston basin CO2 storage targets. Energy Procedia. Spiteri. E.J., R., Juanes, M.J. Blunt, F.M. Orr Jr, 2005. Relative permeability hysteresis: trapping models and application to geological CO2 sequestration. 2005 SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers (SPE 96448), Dallas, TX. Spycher, N., Pruess, K., Ennis-King, J., 2003. CO2-H2O mixtures in the geological sequestration of CO2. I. Assessment and calculation of mutual solubilities from 12 to 100 C and up to 600 bar. Geochim. Cosmochim. Acta. 67, 3015
3031. Verma, A., Pruess, K., 1988. Thermohydrological conditions and silica redistribution near high-level nuclear wastes emplaced in saturated geological formations. J. Geophys. Res. 93, 1159
1173. Wang, Y., et al., 2010. Halite precipitation and permeability assessment during supercritical CO2 core flood. 2010 International Symposium of the Society of Core Analysts (SCA2010-18). Halifax, Nova Scotia, Canada.

13.5.2 Resources IAPWS (International Association for the Properties of Water and Steam), 2007. Revised Release on the IAPWS Industrial Formulation 1997 for the Thermodynamic Properties of Water and Steam. IAPWS. Available online at www.iapws.org/relguide/IF97-Rev.pdf.

Geochemical and biogeochemical features, events, and processes

14

Geochemical interactions are of considerable importance for geological storage and can have an impact over all scales from the near wellbore region, through the host formation and its caprock, and potentially including overlying regional aquifers in the event of leakage from the storage complex. The range of geochemical processes of potential relevance is summarized in Table 14.1. Processes related specifically to wells are discussed in Chapter 16.

14.1

Geochemical FEPs in host rock and caprock

The most important geochemical processes affecting capacity and containment are, respectively, mineral trapping of CO2 within the host formation and potential mineral dissolution and/or deposition processes occurring in the caprock. The related FEPs, impact of co-injected impurities, and the numerical modeling of these processes are discussed in this section, following on from the discussion of the chemistry of CO2 dissolution which was covered in Section 10.1.

14.1.1 Mineral trapping The mineral trapping of CO2 occurs as a result of the precipitation of carbonate minerals formed by the combination of dissolved CO2 with metal cations (predominantly Ca, Fe, and Mg). The primary factors that determine the effectiveness of this type of trapping are therefore: G

G

G

The availability in the formation brine of non-carbonate mineral derived metal cations The dissolution rate of both carbonate and non-carbonate minerals as a function of CO2 presence and resulting solution pH Conditions required for secondary mineral precipitation, such as degree of supersaturation, the availability of nucleation sites, etc.

Table 14.2 lists the minerals most commonly involved in mineral trapping reactions, including the molecular weight, specific gravity range, and potential weight of CO2 that would be fixed by reaction with 1 kg or 1 m3 of mineral. The second part of the table lists the related reaction products.

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00014-3 © 2017 Elsevier Inc. All rights reserved.

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Table 14.1 Summary of geochemical processes relevant for geological storage Region of influence

Geochemical process

Potential geological storage impact

Near wellbore

Mineral dissolution; secondary mineral precipitation as a result of brine concentration, due to water dissolution in injected dry scCO2 Reaction of injected CO2, mainly with aluminosilicate minerals in the host rock, leading to permanent mineral trapping Reaction of injected CO2, with caprock clays and other minerals; dewatering of clays Dissolution or precipitation of minerals in leak paths (e.g., dissolution of a fracture filling carbonate cement) Dissolution of CO2 into potable aquifer

Increase or decrease in near wellbore porosity and permeability; well injectivity reduction (well impairment) or enhancement Mineral trapping; possible permeability impact in rock matrix, fault and fracture planes

Host formation rock

Caprock

Geological leak paths

Overlying regional aquifers

Mineral trapping; possible porosity and permeability changes Potentially rapid increase or decrease in leak path conductance after the onset of advective flow Acidification leading to potential mobilization and transport of trace metals; impact on potable water quality

The acidity and salinity of the carbonated formation brine will be further influenced by the presence of calcium, iron, or magnesium carbonate minerals in the rock matrix, which will be attacked by the weak acid: CaCO3 1 H1 2Ca21 1 HCO2 3

(14.1)

Depending on the availability of hydroxide anions (OH2) from the dissolution of basic minerals, bicarbonate and carbonate ions may also be formed via the reactions: H2 CO3 1 OH2 2HCO2 3 1 H2 O

(14.2)

2 22 HCO2 3 1 OH 2CO3 1 H2 O

(14.3)

Whether these ions remain in solution in the longer term, or contribute to mineral trapping reactions, will depend on brine pH and ionic concentration, as shown schematically in Figure 14.1.

Table 14.2 Typical mineral trapping reactants and reaction products Mineral reactants

Molecular weight

Specific gravity

Potential CO2 fixed kg/kg mineral

kg/m3 mineral

Olivine Mg2SiO4 Fe2SiO4

140.7 203.8

3.2
3.3 4.39

0.62 0.43

2020 1890

Diopside Wollastonite Chlorite Serpentine

MgCaSi2O6 CaSiO3 Mg2.5Fe2.5Al2Si3O10(OH)8 Mg3Fe3Si4O10(OH)8

216.6 116.2 602.7 648.9

3.3
3.6 2.9
3.1 2.6
3.3 2.2
2.9

0.41 0.38 0.37 0.41

1400 1140 1080 1040

Feldspars Albite Anorthite K-feldspar

NaAlSi3O8 CaAl2Si2O8 KAlSi3O8

262.3 278.2 278.4

2.63 2.74 2.59

0.17 0.16 0.16

440 430 410

Forsterite Fayalite

Reaction products Calcite Magnesite Siderite Anhydrite Gypsum

CaCO3 MgCO3 FeCO3 CaSO4 CaSO4  2H2O

Dawsonite Ankerite Alunite Chalcedony Kaolinite

NaAlCO3(OH)2 CaMg0.3Fe0.7(CO3)2 KAl3(OH)6(SO4)2 SiO2 Al2Si2O5(OH)4

Carbon Capture and Storage

Ionic concentration log(Ca2+, Mg2+, Fe2+)

368

Mineral trapping (calite, magnesite, siderite) Solubility trapping (H2CO3)

Ionic trapping (HCO3)

Ionic trapping (CO3 2–)

pH

Figure 14.1 Geochemical trapping dependence on pH. Source: After Gunter et al. (2004).

Typical mineral trapping reactions resulting from the reaction of the weak acid with aluminosilicate minerals present in clays and feldspars, include: G

Precipitation of calcite and kaolinite or dawsonite from the carbonation of albite: 2NaAlSi3 O8 1 H2 CO3 1 H2 O 1 Ca21 24SiO2 1 CaCO3 1Al2 Si2 O5 ðOHÞ4 1 2Na1 (14.4) NaAlSi3 O8 1 H2 CO3 23SiO2 1 NaAlCO3 ðOHÞ2

G

Precipitation of calcite and kaolinite from the carbonation of anorthite: CaAl2 ðSiO4 Þ2 1 CO2 1 2H2 O2CaCO3 1 Al2 Si2 O5 ðOHÞ4

G

(14.6)

Precipitation of dawsonite from the carbonation of K-feldspar: KAlSi3 O8 1 CO2 1 H2 O 1 Na1 23SiO2 1 NaAlCO3 ðOHÞ2 1 K1

G

(14.5)

(14.7)

Precipitation of siderite, dolomite, and kaolinite from the alteration of the clay mineral chlorite: Mg2:5 Fe2:5 Al2 Si3 O10 ðOHÞ8 1 2:5CaCO3 1 5CO2 22:5FeCO3 1 2:5MgCaðCO3 Þ2 1 Al2 Si2 O5 ðOHÞ4 1 SiO2 1 2H2 O

(14.8)

Geochemical and biogeochemical features, events, and processes

369

Field evidence from natural CO2 reservoirs, where dawsonite and kaolinite are observed to be present at the expense of feldspars, provides supports for the occurrence of these reactions in response to elevated CO2 content in the formation brine. However, reactive transport studies also suggest that dawsonite may be a temporary product in geological storage, as its stability requires a high partial pressure of CO2. Since natural analogues can only provide a qualitative insight into the reactions that are likely to dominate in the long term, and laboratory experiments are too short to quantitatively evaluate the very slow reactions involving aluminosilicate minerals, theoretical models are required to provide a quantitative assessment of the rate of these reactions. Typically these models, discussed in the next section, show the reaction rate as proportional to two parameters that are difficult to determine for geological storage representative conditions: the available reactive surface area (A) and the temperature-dependent kinetic rate constant (k(T)). Many factors complicate the determination of representative values for these parameters, including: G

G

G

G

G

G

Dependence of rate on variable mineral composition and morphology (crystalline state) Dependence of rate on proximity to equilibrium Presence of catalysts or inhibitors of the reaction Need to quantify reaction rate over a range of temperatures and pressures Difference between total and reactive surface areas of minerals Differences between dissolving and precipitating surface areas (nucleation sites)

These and other complications can introduce uncertainties of several orders of magnitude in the capacity for mineral trapping and the attendant changes in host formation properties such as porosity and permeability. This is illustrated by the results of a number of geochemical models representing the Utsira aquifer at Sleipner (summarized by Gaus, 2010) where, depending on mineralogical assumptions, different models helpfully predict that the fraction of injected CO2 trapped as mineral after 10,000 years lies between ,1% and 100%!

14.1.2 Geochemical processes in the caprock Unlike the host formation, where penetration of CO2 or CO2-saturated brine is enabled by the higher permeability, geochemical reactions in the caprock are limited by the extremely low permeability to shale interfaces, including the surface of fractures of all scales that allow fluid penetration into the caprock. Reactions such as those described in Reactions (14.4)
(14.7) can equally occur at these accessible caprock sites, to the extent that the relevant minerals are present, but the predominant reactions will be those involving clay minerals such as chlorite, as shown in Reaction (14.8) and for K-feldspar and Mg-chlorite: KAlSi3 O8 1 2:5Mg5 Al2 Si3 O10 ðOHÞ8 1 12:5CO2 2KAl3 Si3 O10 ðOHÞ2 1 12:5MgCO3 1 1:5Al2 Si2 O5 ðOHÞ4 1 4:5SiO2 1 6H2 O

(14.9)

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Carbon Capture and Storage

Although these reactions may occur only within an interface layer of limited thickness (perhaps 5
10 m), and will therefore contribute little to overall mineral trapping capacity, more significant is the reduction in porosity and permeability resulting from the increased volume of reaction products. In Reaction (14.9), for example, the solid volume of products is some 18.5% higher than that of the reactant minerals. An example has been reported by Johnson et al. (2004) for Sleipner conditions, where the abundances of K-feldspar and Mg-chlorite in the caprock are 5% and 10%, respectively. Reaction (14.9) is there expected to reach an effective end point after some 130 years when the shale porosity is halved and permeability has been reduced by an order of magnitude (Figure 14.2). While the reactions described above would enhance the caprock sealing capacity, the possibility of seal degradation also exists if reaction product volume is lower than the reactant volume, that is if the standard molar volume change of the reaction is negative: ΔVr0 5 Vp0
VR0 , 0

(14.10)

3.0

5.0

2.5

4.5

Porosity (% volume)

Permeability (µD)

where VP0 and VR0 are the standard molar volume of reaction products and reactants, respectively. Examples of reactions include dissolution of K-feldspar, dolomite (CaMg(CO3)2), or anhydrite dissolution, the latter reaction, after secondary precipitation of calcite, resulting in a 13% reduction in solid volume (Rochelle et al., 2004). The potential for these reactions, which can enhance shale porosity and permeability, further increasing the interface area and enabling the reaction to continue progressively deeper into the caprock, will therefore require careful consideration during site characterization. This will include caprock coring, mineralogical analysis, and batch geochemical experiments, to identify the main reactions taking place and provide input to reactive modeling studies.

2.0 1.5 1.0 0.5

4.0 3.5 3.0 2.5 2.0

0.0 0

20

40

60

80

Time (years)

100 120 140

0

20

40

60

80

100 120 140

Time (years)

Figure 14.2 Sleipner caprock porosity and permeability reduction due to Equation (14.9). Source: After Johnson et al. (2004).

Geochemical and biogeochemical features, events, and processes

371

14.1.3 Geochemical reactions kinetics Complex geochemical reactions such as those indicated above proceed via a sequence of elementary steps, such as the uptake of a proton or hydroxide ion, the complete sequence of steps being known as the reaction mechanism. Any reaction may proceed via a number of different mechanisms and for most of the mineral weathering reactions relevant to geological storage, three mechanisms may be important—an acid mechanism which is dependent on H1 concentration, a base mechanism dependent on OH2 concentration, and a neutral mechanism. A general expression for the kinetic rate of mineral weathering reactions has been given by Lasaga et al. (1994) as: rm 5 6km Am 1 2 ðQm =Km Þθ η

(14.11)

where the subscript m denotes the mineral reaction, km is the rate constant (mol/m2/s) and Am is the specific reactive surface area (m2 per unit under consideration). Km, the equilibrium constant, and Qm, the reaction quotient, are discussed below. Parameters θ and η are empirically determined but are commonly assumed to be unity. The resulting kinetic rate is positive for mineral dissolution (the forward reaction) and negative for precipitation (the reverse reaction). The reaction quotient, Qm, and equilibrium constant, Km, depend on the concentrations of reactants and reaction products. For the reaction: αA 1 βB2δD 1 εE

(14.12)

where A and B are the reactants, D and E the reaction products, and α, β, δ, and ε are the stoichiometric coefficients, the reaction quotient is given by: Qm 5 fDgδt fEgεt =ðfAgαt fBgβt Þ

(14.13)

where {S}t denotes the time-dependent activity of species S at time t. When a reaction reaches equilibrium, the reaction quotient is equal to the equilibrium constant: Km 5 fDgδ fEgε =ðfAgα fBgβ Þ

(14.14)

Thus, if Qm , Km, product concentrations are low relative to equilibrium and the forward reaction is dominant, while Qm . Km indicates high product concentrations relative to equilibrium so that the reverse reaction dominates. The rate constant km depends on temperature and on the activation energy of the reaction mechanism and is given for the three mechanisms (see Xu et al., 2010; Appendix A): 1

km;acid 5 k25;H exp½ð2Ea;H =RÞð1=T
1=298:15ÞfHgnðH

Þ

(14.15)

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Carbon Capture and Storage

2

km;base 5 k25;OH exp½ð2Ea;OH =RÞð1=T
1=298:15ÞfOHgnðOH

Þ

km;neutral 5 k25;nu exp½ð2Ea;nu =RÞð1=T
1=298:15Þ

(14.16) (14.17)

where Ea is the activation energy of the mechanism, k25 is the rate constant at 25 C for each mechanism, R is the gas constant (8.314 J/mol/K), T is the absolute temperature (K), and n is the activity exponent for the mechanism with respect to the species (H1 or OH2), also known as the order of the reaction (0 , n , 1). Note that by definition the activity term for the neutral mechanism is unity. The overall reaction rate constant is then the sum of the rates for the individual mechanisms: km 5 km;acid 1 km;base 1 km;neutral

(14.18)

Table 14.3 gives some kinetic rate parameters (Ea, k25, and n(H1)) for the neutral and acid dissolution mechanisms of some relevant minerals. The rate constant for the base mechanism of these reactions is typically 4 or more orders of magnitude smaller than the constant for the neutral mechanism.

14.1.4 Geochemical impact of gas impurities As well as the impact on physical properties and flow behavior, as discussed in the previous chapter, the presence of impurities in the injection stream can modify the geochemical response of the storage complex, both in the short term in the near wellbore region, with possible implications for injectivity, and in the longer term

Table 14.3 Kinetic rate parameters for mineral dissolution reactions Mineral

Quartz Calcite Dolomite Oligoclase K-feldspar

Neutral mechanism

Acid mechanism

k25,nu (mol/m2/s)

Ea,nu (kJ/mol)

k25,H (mol/m2/s)

Ea,H (kJ/mol)

n(H1)

1.02 3 10214 1.55 3 1026 2.95 3 1028 1.45 3 10212 3.89 3 10213

87.7 23.5 52.2 69.8 38.0

5.01 3 1021 6.46 3 1024 2.14 3 10210 8.71 3 10211

14.4 36.1 65.0 51.7

1.0 0.5 0.46 0.5

Source: Data from Xu et al. (2010).

Geochemical and biogeochemical features, events, and processes

373

throughout the host formation, with implications for trapping. In contrast to the impact on physical properties, which is most pronounced for non-condensable components, the impurities with the greatest potential for geochemical impact on storage performance are SOx, NOx, and H2S. As an example, reactive transport studies of the Frio formation in Texas showed that substantial H2S content in the injection stream had little impact whereas even small amounts of SO2 had a significant geochemical impact due to the extremely acidic conditions in the near wellbore region (see Knauss et al., 2005). Other modeling studies have also predicted that the generation of sulfuric acid and the low pH conditions resulting from coinjection of H2S and particularly SO2 result in aggressive mineral dissolution and porosity enhancement in the near wellbore region, and subsequent deposition of sulfur as pyrite (FeS), alunite (KAl3(SO4)2(OH)6), or anhydrite (CaSO4) as the dissolved species are transported away from the acidified zone. These reactions take place under aqueous conditions, so that the near wellbore impact will cease once a dry-out zone is established, although this would not be the case if brine is coinjected as a trapping enhancement strategy (Chapter 17). Apart from a few such site- and composition-specific studies, the broad base of experimental data on the geochemical impact of injection stream impurities that is needed to underpin recommendations for storage operations is currently lacking. The SIGARRR project (see Corvisier et al., 2017 and Resources) aims to address this lack of data and develop tools that can provide the basis for such recommendations.

Deposition of elemental sulfur One geochemical process involving impurities that can continue in the dry-out zone and has the potential to significantly affect near wellbore porosity and permeability is the Claus reaction: 2H2 S 1 SO2 5 3S 1 2H2 O

(14.19)

which would result in the deposition of elemental sulfur in the near wellbore pore space (see IEAGHG, 2011). This reaction is catalyzed by aluminosilicate minerals, and clay mineral surfaces will therefore provide reaction sites although the reaction rate will be expected to drop once these surfaces become inaccessible due to deposition of a layer of sulfur. The presence of hydrogen or oxygen as additional impurities would also have an impact by reducing or oxidizing any deposited sulfur to H2S or SO2, respectively. Given the many competing factors involved, the impact of the Claus reaction can only be assessed by undertaking flow experiments using core material from the prospective host formation under in situ conditions and over the full expected composition range of the injection stream.

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Carbon Capture and Storage

Mineral trapping impact The presence of SO2 or H2S in the injected CO2 stream may also have a significant positive impact on mineral trapping if the host formation contains significant ferric iron, for example, in sediments such as redbeds (see Palandri and Kharaka, 2005). In this case, SO2 or H2S serves to reduce ferric to ferrous iron, which can then be precipitated as siderite: Fe2 O3 1 2CO2 1 SO2 1 H2 O ! 2FeCO3 1 H2 SO4

(14.20)

Compared to the very slow dissolution and reaction rates for the aluminosilicate mineral species described above, this trapping mechanism has the advantage of a much faster reaction rate, resulting in trapping as siderite on a timescale of years to decades rather than centuries to millenia. Where contaminant gases are likely to be present in the injection stream, mineralogical analysis of potential host formations, using techniques such as thin-section evaluation, XRD, cathodoluminescence, and scanning electron microscopy, will have even greater importance as a characterization requirement for site assessment and selection. Reactive transport modeling will need to include contaminant gases and will have to be validated by static batch and core flow experiments in order to assess the site-specific impact of contaminants—both short term and long term— and to establish allowable limits on contaminant concentration in the injection stream.

14.2

Geochemical FEP in overlying potable aquifers

Depending on the mineralogy of the sediments comprising the aquifer, leakage of CO2 into potable aquifers could result in acidification of the water, which in turn can lead to the dissolution of mineral phases containing trace metals such as lead, arsenic, or cadmium and the mobilization of those metals (see Wang and Raffe, 2004). Minerals that could release trace metals or radionuclides into groundwater are listed in Table 14.4. Table 14.4 Potential mineral sources of trace metals and radionuclides Trace metal

MCL (µg/L)

Source minerals

Chemical formulae

Lead Arsenic

15 10

Cadmium Uranium

5 30

Galena Arsenolite Arsenopyrite Greenockite Uraninite (Pitchblende)

PbS As2O3 FeAsS CdS UO2, UO3

Geochemical and biogeochemical features, events, and processes

375

The MCL or Maximum Contaminant Level is defined under the US EPA National Drinking Water Regulations as the highest level of a contaminant that is allowed in drinking water. The mineralogy of the aquifer is critical in determining the potential for trace metal mobilization, since pH buffering by carbonate minerals and re-adsorption by clays can have a significant impact on the maximum aqueous concentration achieved under a given leakage scenario. Reactive transport models are being widely used to study such interactions (see Zheng et al., 2009). Natural analogues also demonstrate that CO2 influx into potable aquifers does not inevitably lead to a deterioration in water quality. In Europe, many naturally carbonated waters have been highly prized since Roman times and are now commercially exploited under well-known brand names such by Perrier, Vichy, and San Pellegrino. Further investigation of these analogues may provide valuable insights into the risks posed to potable water resources as a result of leakage from geological storage sites.

14.3

Reactive transport modeling of the storage complex

Reactive transport modeling brings together the geochemical FEPs discussed in this chapter and those related with rock properties and fluid flow discussed in Chapter 13. Figure 14.3 shows schematically the coupling of geochemical and fluid flow processes through the linking properties of porosity and permeability and also indicates the extension of this coupling to include geomechanical properties and processes. Although simulation tools and basic thermodynamic and rate kinetic data are available to build reactive transport models and to assess the sensitivity of geological storage performance to geochemical FEPs, actual experimental data under representative subsurface conditions are not generally available to perform model validation. Baseline geochemical data is therefore an important objective during storage site assessment, particularly if screening studies indicate that geochemical FEPs may have a significant impact on performance. Many authors in this field caution that the results of reactive transport simulations should be interpreted with care, given the simplified geometry and structure of such models, which do not capture the natural 3D variability and range of scales, and the lack of reliable, representative reaction rate parameters for bulk reactions. Geochemical models are useful to indicate the dominant reactions that can occur in different zones within the storage complex, but their ability to make quantitative predictions about these reactions is still limited and is the subject of broad ongoing research and simulation code development efforts.

14.3.1 Fluid flow consequences of geochemical FEP The initial decrease in pH that results when CO2 comes into contact with the formation brine will lead to rapid dissolution of minerals such as calcite in the region

376

Carbon Capture and Storage

Stress state

Heat transfer

Mechanical strain

Porosity

Geomechanical processes

Hydrodynamic processes Permeability

Fluid flow

Chemical reactions

Chemical equilibria

Geochemical processes

Figure 14.3 Coupling of geochemical, hydrodynamic, and geomechanical processes. Source: After Johnson et al. (2004).

close to the wellbore, which will continue until this region is completely dried. The impact on injectivity will be a balance between this mineral dissolution and any halite deposition that occurs during this drying process. In the longer term, the geochemical reactions leading to mineral trapping may affect flow properties either in the host formation or in the caprock.

Host formation impact Deposition of secondary minerals in the host formation can lead to reduced porosity and permeability, which can be substantial if deposition occurs in narrow pore throats. Various modeling studies have indicated porosity reductions of 10%
25% in the region of mineral deposition, and porosity increases of 40% or more in the near wellbore dissolution zone. The translation of a predicted porosity change to a permeability change is not straightforward and is a significant knowledge gap. Expressions such as the modified Kozeny
Carman equation or the fractal “pigeon hole” model express permeability in terms of parameters such as a representative grain radius (rgrain), and the effective capillary radius (reff) and tortuosity (T) of the pore network. The impact of dissolution and precipitation therefore depends on the effect that these processes have on grain and capillary radii and tortuosity, which in turn will depend on the distribution of reaction sites on the pore scale (e.g., whether dissolution and

Geochemical and biogeochemical features, events, and processes

377

precipitation sites are randomly distributed across all grain sizes and surfaces or predominate on either large or small grains). At present there are no generic approaches to this problem. The wettability of grain surfaces can also be affected, resulting in changes in the capillary pressure and relative permeability with consequent impact, on an operational timescale, on injectivity and capacity. In CO2 flood EOR projects, the full range of possible permeability effects have been observed in different formations—permeability reduction, no change or increase, depending on the formation mineralogy and the chemistry of co-injected brine (see Shiraki and Dunn, 2000).

Caprock impact Unlike the host formation where the acidified brine contacts a large volume of the host formation due to advective (pressure driven) fluid flow, CO2 or brine transport into an intact caprock occurs predominantly through diffusion, so that only small quantities of CO2 are involved and will migrate only a short distance into the caprock. Nevertheless, geochemical reactions identical to those occurring in the host formation can result in permeability and wettability changes that could potentially impact on containment by reducing capillary entry pressure and increasing permeability within the region contacted by CO2. The presence of carbonate minerals in the caprock would be a particular concern due to their high reactivity, emphasizing the requirement for caprock mineralogical analysis during storage site characterization. As well as its variable impact on the rock matrix and pore space within the storage complex, mineral dissolution could either exacerbate or mitigate a containment risk if this occurred along potential leak paths such as fault or fracture planes in the caprock. Observations from natural analogues suggest that geochemical processes due to the movement of CO2-rich water along faults or fractures can have a range of effects from porosity and permeability enhancement to self-sealing, depending on the site-specific conditions (see, e.g., May, 2005). If impurities such as SOx and NOx are expected to be present in the injected stream at relatively high concentrations ( .1%), the dissolution rate of carbonate or aluminosilicate minerals in the caprock as a result of the formation of sulfuric and nitric acid can become significant. The positive feedback resulting from increased porosity and permeability, leading to increased penetration of corrosive fluid into the caprock, may then pose a threat to caprock integrity. However, at SOx and NOx concentrations in the 10
200 ppm range, more typical of captured CO2, this is less likely to be a concern.

14.3.2 Geomechanical consequences of geochemical FEP Host formation impact As well as the impact on porosity and permeability, dissolution and/or deposition of secondary minerals in the host formation will alter the geomechanical properties of

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the affected region. The dissolution of minerals, particularly those contributing to rock cementation, will reduce rock strength and consequently reduce the fracture initiation pressure. This effect could be exacerbated if pore plugging minerals are deposited in the near wellbore region, necessitating an increase in injection pressure to achieve a target injection rate. If mineralogical characterization, for example, using XRD to examine rock cement mineralogy, indicates a significant presence of soluble minerals, additional evaluation such as pre- and post-flush rock strength tests on core material or preand post-injection minifrac tests on an injection pilot would provide a basis for assessing this geochemical
geomechanical coupling.

Caprock impact Mineral dissolution and deposition in the lower caprock will affect the geomechanical properties of this interval and, when coupled with the effect of increased pore pressure on the effective stress, can influence the reactivation of existing fractures or opening of new fractures. Such coupled geochemical and geomechanical effects on the caprock have been examined under Sleipner conditions, by considering the competing influence of geochemical and geomechanical processes on the aperture of microfractures in the Utsira caprock (see Johnson et al., 2005). The two main effects considered, shown schematically in Figure 14.4, are the net aperture increase through the pore pressure cycle on an operational timescale and the longer term aperture reduction through mineral deposition. For Sleipner conditions it was concluded that, although existing microfractures were widened by the operational pressure cycle, geochemical reactions could fully counterbalance this widening in the longer term, for values of the critical reaction

Caprock microfractures

CO2 plume

Microfracture wall Geomechanical processes Geochemical processes

Aqueous wetting phase

Mobile CO2 phase

Figure 14.4 Geomechanical and geochemical processes affecting caprock microfracture aperture. Source: After Johnson et al. (2005).

Geochemical and biogeochemical features, events, and processes

379

parameters (namely, diffusion length and reaction progress) that are within the normal range.

14.4

Biogeochemical FEPs

The potential for microbial activity in the subsurface to have an impact on engineered processes is evident from the occurrence of reservoir souring in waterflooded oil reservoirs, as a result of the generation of hydrogen sulfide by sulfate-reducing bacteria (SRB). This occurs when sulfate is introduced into a reservoir that contains nutrient, in the form of volatile fatty acids in the oil phase, while the bacteria may be initially present in the reservoir or may also be introduced in the injected water. A common mitigation measure also employs the subsurface microbiome—by dosing the injected water with nitrate, nitrate-reducing bacteria are encouraged, limiting the growth of SRBs. Various microbial processes have also been investigated and applied to EOR, particularly in heavy oil reservoirs. Microbially mediated processes have the potential to influence geological storage in saline aquifers as a result of either: G

G

The reduction of permeability in preferential flow paths by the buildup of pore lining or pore-throat clogging cellular and extracellular biomass (biofilm growth) Microbially enhanced geochemical dissolution and precipitation (enhanced biomineralization)

Several factors, summarized in Table 14.5, are required to coexist in order to sustain a microbial population, and this compound requirement provides a degree of control over the location and duration of engineered microbial activity in the host formation.

14.5

Impact of CO2 injection on microbial communities

The impact of CO2 injection on microbial communities was investigated as part of the Ketzin CO2 injection pilot project in Germany (see Morozova et al., 2010). Genetic fingerprinting analyses of baseline formation water samples from the target reservoir at 647 m depth revealed an active microbial community (109 cells/L), comprising fermentative and sulfate-reducing bacteria and microorganisms of the domain Archaea. Prior to CO2 injection, the injection and monitoring wells were cleaned up to remove drilling fluids by nitrogen lifting. This resulted in a dramatic decline in microbial activity, as a result of the removal from the drilling mud and near wellbore fluids of the organic substrates required for microbial metabolism, with the cell counts (Bacteria and Archaea) declining from c. 109 and 107 cells/L, respectively, to below the detection limit of B106 cells/L.

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Carbon Capture and Storage

Table 14.5 Requirements for microbial activity in a geological storage host formation Requirement

Description

Microbial population

The microbial population may be indigenous, as is often the case in oil reservoir souring, or may grow from an inoculation of nonindigenous bacteria. For engineered biofilm growth or mediated mineralization, inoculation of the selected non-indigenous strains is a likely requirement The nutrient (or substrate) provides the food to sustain microbial activity. Examples of nutrients used in anaerobic bioremediation of contaminated soils include molasses, sodium lactate, and vegetable oil. Nitrogen, phosphorus, and other micronutrients may also be required The essential component of respiration that enables the organism to create energy from the nutrient. Examples of electron acceptors are oxygen, in animal respiration, CO2 for photosynthesis, sulfide in SRB respiration. Nitrate is an electron acceptor that is used for bioremediation of contaminated soils under anaerobic conditions and also, as noted above, as an oil reservoir souring treatment The temperatures and pressures typical of geological storage host formations (30
100 C, 10
30 MPa) are not challenging for microbe survival, but biocidal conditions can occur for high brine salinity, or conditions of extreme acidity or alkalinity

Nutrient supply

Electron acceptor

Non-biocidal environment

The recovery of these communities in the vicinity of the observation well was interrupted after 2 weeks by the arrival of CO2 from the injection well, 50 m distant from the observation, accompanied by a drop in brine pH from 7.5 to 5.5. Archaea proved more tolerant to this decrease in pH and initially outcompeted the bacteria. However, between 2 and 5 months after CO2 arrival, the bacteria adapted to the lower pH, and by 5 months after CO2 arrival cell counts were close to their preinjection levels. The Ketzin pilot results reveal both a significant impact of CO2 injection on microbial communities and also the ability of these organisms to adapt to the varying geochemical conditions that they encounter as a result of CO2 injection.

14.6

Biofilm growth

Biofilms are formed from living microbial populations and microbial residues within a protective matrix of extracellular polymeric substances (EPSs).

Geochemical and biogeochemical features, events, and processes

381

Experimental studies and coupled numerical models of hydrodynamic and microbial processes have demonstrated that significant permeability reduction (a 99% permeability loss from 40 to 0.4 mD) can be achieved in porous media under representative geological storage conditions of temperature and pressure through the growth of pore lining and pore filling biofilms (see Mitchell et al., 2009, 2010; Ebigbo et al., 2010). Subsequent challenge to the microbial population by starvation (removal of nutrients) or by flooding with scCO2 was seen to have a limited effect in restoring permeability. Figure 14.5 shows Field Emission Scanning Electron Microscopy (FESEM) images of a Berea sandstone core before and after its inoculation with a bacterial culture and subsequent “challenge” with a pulse of scCO2.

14.6.1 Caprock leakage remediation These results suggest that engineered biofilms might have the potential to plug preferential leak paths, for example, through a damaged caprock. This could be achieved either as a precautionary or a remedial measure and would involve the periodic injection of nutrient and an electron acceptor (e.g., nitrate or sulfate) to sustain the biofilm growth. A limitation on the application of this process is imposed by the deactivating effect of scCO2, particularly for microbial cells that are suspended in the pore fluid (planktonic cells), resulting in a cessation of microbial activity and a partial restoration of the initial permeability. In contrast, microbes in biofilms attached to grain surfaces are more resistant to scCO2, as a result of the protection provided by the EPS matrix. One way in which this limitation might be overcome, thereby achieving a more permanent permeability reduction, is by using microbial processes to deposit of pore plugging minerals (biominerals), as discussed in the following section.

Figure 14.5 FESEM images of Berea sandstone (A) before and (B) after microbial inoculation and scCO2 challenge. Source: From Mitchell et al. (2009), with permission.

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Carbon Capture and Storage

14.6.2 Microbially enhanced trapping As well as the possibility of sealing or at least reducing the permeability of leak paths, microbially mediated permeability reduction could also have a significant impact on the storage capacity of host formations by enhancing residual trapping. Since residual trapping only occurs as brine imbibition takes place into the pore volume swept by the injected CO2 plume, residual trapping can be enhanced by forcing the plume to take alternative flow paths through the host formation. This would result in a larger gross rock volume being swept by the plume, increasing the fraction of injected CO2 trapped at the residual saturation. Flow path modification could be achieved by periodic blocking of preferred paths through biofilm growth as a result of the batch injection of nutrients and electron acceptors and would also be enhanced by microbially induced mineral deposition.

14.7

Enhanced biomineralization

As discussed in Chapter 10, biomineralization refers to the precipitation of minerals, such as calcium carbonate, as a consequence of microbial metabolic activity. The microbial activity can impact mineralization in two ways: 1. by contributing the chemical species required to form the precipitate (e.g. carbonate ions), and/or 2. by changing the chemical conditions (e.g., pH increase) to drive a reaction toward precipitation.

Biomineralization has been investigated in modeling studies and laboratory-scale experiments for applications in EOR (see Ferris et al., 1996) and also to enhance geological storage. In the EOR and geological storage applications, the microbial mediated hydrolysis of urea ((NH2)2CO) leading to the precipitation of calcium carbonate has been investigated (see Mitchell et al., 2010). The overall hydrolysis and precipitation reactions are as follows: 22 ðNH2 Þ2 CO 1 2H2 O22NH1 4 1 CO3

(14.21)

Ca21 1 CO22 3 2CaCO3

(14.22)

The precipitation reaction is driven to the right by alkaline conditions, which result from the production of OH2 ions during the ureolysis. Calcium ions are provided by the formation brine, while the carbonate ions are also a product of the ureolysis, which means that the mineralization does not result in a net transfer of CO2 from a supercritical or gaseous phase. Figure 14.6 shows the result of microbially induced calcite precipitation in a 2D flow reactor under laboratory conditions. The 1 mm flow channels became completely plugged after just 20 hours of operation.

Geochemical and biogeochemical features, events, and processes

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Figure 14.6 MICP in a 2D flow reactor. Source: From Cunningham et al. (2009), with permission.

The ureolytic reaction has the potential to enhance geological storage security and capacity via two mechanisms: first, the precipitation will reduce porosity and permeability and can contribute to the sealing of preferential flow or leak paths and second, the alkaline conditions resulting from ureolysis increase the solubility of CO2 in formation brine, increasing solubility trapping. Biomineralization is unlikely to occur close to the point of injection, where high CO2 partial pressure results in conditions that are toxic to microbial populations as well as strong acidic buffering, which prevents the ureolytic reaction from creating the high pH conditions necessary for precipitation. Conditions that are conducive to the biomineralization process are more likely to occur in peripheral areas, where CO2 partial pressure is lower. Site-specific experimental studies can assess the potential impact of ureolytic bacteria and, where this is significant, enable the process to be coupled to the model of the storage complex.

14.8

Subsurface microbial recycling of CO2

The final step in the decay of organic matter is the reduction of carbon to form methane (Reaction (14.23)), and the methanogenic microbes responsible for this process, from the domain Archaea, are present in such diverse environments as the human gut and deep hydrothermal aquifers: 4H2 1 CO2 ! CH4 1 2H2 O

(14.23)

The hydrogen required as the energy source for this microbial process can be derived either from organic matter or from water reacting with feldspar, silicates, or quartz at moderate to high temperatures (25
275 C). For example, the reaction of water with Fayalite, the iron-rich end-member of the Olivine silicate mineral group, a common constituent of basalts, is

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Carbon Capture and Storage

3Fe2 SiO4 1 2H2 O ! 2Fe3 O4 1 3SiO2 1 2H2

(14.24)

which, combined with microbial methanogenesis, yields: 6Fe2 SiO4 1 2H2 O 1 CO2 ! 4Fe3 O4 1 6SiO2 1 CH4

(14.25)

This process opens up the intriguing possibility of microbial recycling CO2 into methane, by injection of CO2 into a deep anoxic aquifer that contains both a community of methanogenic Archaea and an organic or mineral source of hydrogen (see Koide, 1999). Ecosystems that could support this process have been identified in deep basalt aquifers in the Columbia River Basalt Group—a flood basalt system covering over 160,000 km2 of the Pacific Northwest of the United States (see Stevens and McKinley, 1995). This concept is at an early research and development stage, but the appealing symmetry of regenerating hydrocarbons in the subsurface by microbial recycling of the product of hydrocarbon combustion will undoubtedly motivate further work toward proof of concept.

14.9 References and resources 14.9.1 References Corvisier, J., et al., 2017. Simulations of the impact of co-injected gases on CO2 storage, the SIGARRR project: processes and geochemical approaches for gas-water-salt interactions modeling. Energy Procedia. 114, 3322
3334. Cunningham, A.B., Gerlach, R., Spangler, L.H., Mitchell, A.C., 2009. Microbially enhanced geologic containment of sequestered supercritical CO2. Energy Procedia. 1, 3245
3252. Ebigbo, A., Helmig, R., Cunningham, A.B., Class, H., Gerlach, R., 2010. Modelling biofilm growth in the presence of carbon dioxide and water flow in the subsurface. Adv. Water Res. 33, 762
781. Ferris, F.G., Stehmeier, L.G., Kantzas, A., Mourits, F.M., 1996. Bacteriogenic mineral plugging. J. Can. Pet. Technol. 35, 56
61. Gaus, I., 2010. Role and impact of CO2
rock interactions during CO2 storage in sedimentary rocks. Int. J. Greenhouse Gas Control. 4, 73
89. Gunter, W.D., Bachu, S., Benson, S., 2004. The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage of carbon dioxide. Geological Society of London. Geological Storage of Carbon Dioxide; Special Publications. 233, 129
145. IEAGHG (International Energy Agency Greenhouse Gas R&D Programme), 2011. Effects of impurities on geological storage of CO2. IEA GHG Report 2011/04. IEA Environmental Projects, Cheltenham, UK. Johnson, J.W., Nitao, J.J., Knauss, K.G., 2004. Reactive transport modelling of CO2 storage in saline aquifers to elucidate fundamental processes, trapping mechanisms and sequestration partitioning. Geol. Soc. London Spec. Publ., 107
128.

Geochemical and biogeochemical features, events, and processes

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Johnson, J.W., Nitao, J.J., Morris, J.P., 2005. Reactive transport modeling of cap-rock integrity during natural and engineered CO2 storage. In: Thomas, D.C., Benson, S.M. (Eds.), Carbon Dioxide Capture for Storage in Deep Geologic Formations. Elsevier, Amsterdam, Netherlands. Knauss, K.G., Johnson, J.W., Steefel, C.I., 2005. Evaluation of the impact of CO2, co-contaminant gas, aqueous fluid and reservoir rock interactions on the geological sequestration of CO2. Chem. Geol. 217, 339
350. Koide, H., 1999. Geological sequestration and microbiological recycling of CO2 in aquifers. Proceedings of the 4th International Conference on Carbon Sequestration, 30 August
2 September 1998, Interlaken, Switzerland. Elsevier Science Ltd, UK. Lasaga, A.C., Soler, J.M., Ganor, J., Burch, T.E., Nagy, K.L., 1994. Chemical weathering rate laws and global geochemical cycles. Geochim. Cosmochim. Acta. 58, 2361
2386. May, F., 2005. Alteration of wall rocks by CO2-rich water ascending in fault zones: Natural analogues for reactions induced by CO2 migrating along faults in siliciclastic reservoir and caprocks. Oil Gas Sci. Technol. Rev. IFP. 60, 19
32. Mitchell, A.C., Phillips, A.J., Hiebert, R., Gerlach, R., Spangler, L.H., Cunningham, A.B., 2009. Biofilm enhanced geologic sequestration of supercritical CO2. Int. J. Greenhouse Gas Control. 3 (90
99), . Mitchell, A.C., Dideriksen, K., Spangler, L.H., Cunningham, A.B., Gerlach, R., 2010. Microbially enhanced carbon capture and storage by mineral-trapping and solubilitytrapping. Environ. Sci. Technol. 44, 5270
5276. Morozova, D., Zettlitzer, M., Let, D., Wu¨rdemann, H., The CO2SINK Group, 2010. Monitoring of the microbial community composition in deep subsurface saline aquifers during CO2 storage in Ketzin, Germany. Energy Procedia. 4 (4362
4370). Nghiem, L., V. Shrivastava, B. Kohse, P. Sammon, 2004. Simulation of CO2 EOR and sequestration processes with a geochemical EOS compositional simulator. Petroleum Society of Canada. Presented at the 2004 Canadian International Petroleum Conference, Calgary, Alberta. Palandri, J.L., Kharaka, Y.K., 2005. Ferric iron-bearing sediments as a mineral trap for CO2 sequestration: iron reduction using sulfur-bearing waste gas. Chem. Geol. 217, 351
364. Rochelle, C.A., Czernichowski-Lauriol, I., Milodowski, A.E., 2004. The impact of chemical reactions on CO2 storage in geological formations: a brief review. Geological Society of London. Geological Storage of Carbon Dioxide; Special Publications. 233, 87
106. Shiraki, R., Dunn, T.L., 2000. Experimental study on water-rock interactions during CO2 flooding in the Tensleep Formation, Wyoming, USA. Appl. Geochem. 15, 265
279. Stevens, T.O., McKinley, J.P., 1995. Lithautotrophic microbial ecosystems in deep basalt aquifers. Science 20, 450
455. Taberner, C., G. Zhang, L. Cartwright, 2009. Injection of supercritical CO2 into deep saline carbonate formations, predictions from geochemical modeling. Society of Petroleum Engineers (SPE 121272). 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, Netherlands. Wang, S., Raffe, P.J., 2004. Dissolution of a mineral phase in potable aquifers due to CO2 releases from deep formations; effect of dissolution kinetics. Energy Convers. Manage. 45 (2833
2848), .

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Wang, X., Conway, W., Burns, R., McCann, N., Maeder, M., 2010. Comprehensive study of the hydration and dehydration reactions of carbon dioxide in aqueous solution. J. Phys. Chem. A. 114, 1734
1740. Xu, T., Kharaka, Y.K., Doughty, C., Freifeld, B.M., Daley, T.M., 2010. Reactive transport modeling to study changes in water chemistry induced by CO2 injection at the Frio-I Brine Pilot. Chem. Geol. 271, 153
164. Zheng, L., Apps, J.A., Zhang, Y., Xu, T., Birkholzer, J.T., 2009. On mobilization of lead and arsenic in groundwater in response to CO2 leakage from deep geological storage. Chem. Geol. 268, 281
297.

14.9.2 Resources British Geological Survey (Geochemical and Geomicrobiological research facilities): www. bgs.ac.uk/sciencefacilities/laboratories/research/ccs. Global CCS Institute publication—Geochemistry and Reactive Transport Modeling of CO2 Storage (M. Azaroual). Available at http://hub.globalccsinstitute.com/publications/1stco2-geological-storage-modelling-network-meeting/geochemistry-and-reactive. National Geosequestration Laboratory, Perth, Australia (Geochemical research facility): www.ngl.org.au/facility/geochemistry. SIGARRR project (experimental studies and simulation code development to provide the basis for guidelines on geochemical limits on injection stream impurities): www.agencenationale-recherche.fr/?Projet 5 ANR-13-SEED-0006.

Hydrological and environmental features, events, and processes

15

As discussed above in the context of geomechanical features and processes, the injection of CO2 into subsurface formations will result in an increase in pore pressure, on a distance scale that can range from the near vicinity of the well to a reservoir, basin-wide or regional scale, and on a timescale that may be limited to the injection period or may persist for centuries or longer. The hydrological consequences of this pressure perturbation will need to be assessed whenever actual or potential water resources are present in the area of the storage complex or are more distant but still hydraulically connected to it. Other environmental factors—including health and safety risks to human populations—will be of greatest significance when considering potential onshore storage sites where, as experience on early demonstration project proposals has already shown, public perception and risk tolerance will play a role in determining project viability.

15.1

Local- and regional-scale hydrological features, events, and processes

The most important hydrological issues to be considered during feasibility assessment, design, and operation of geological storage projects will be: G

G

G

G

The pressure buildup, both near-field and far-field, resulting from planned projects and potential future expansion Brine migration as a result of pressure buildup, particularly flows with the potential to impact on drinking water resources in overlying aquifers or in shallower updip areas of the storage formation The impact of the hydrodynamic regime on plume movement and CO2 trapping Potential interactions between multiple storage projects operating on the same hydraulic unit

Figure 15.1 shows a schematic regional aquifer in cross section. The aquifer will be charged by meteoric water where the formation outcrops at the surface (shown on the right of the figure) and salinity will increase progressively away from the outcrop, reaching at some depth the locally applied limit defining USDW—10,000 mg/L total dissolved solids in the case of the current US EPA definition. The geological, fluid flow and other features and processes discussed in Chapters 12
14 in relation to the host formation are equally relevant for the whole Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00015-5 © 2017 Elsevier Inc. All rights reserved.

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Depth below sea level (m)

Land surface

Meteoric recharge Hydraulically connected freshwater aquifer

0

Impermeable aquitard

1000

Saline aquifer Impermeable aquitard

2000

Basin scale-10s of kilometers

3000

Figure 15.1 Schematic cross section of an open regional aquifer.

of the connected hydrological system. Some additional hydrology-specific features and processes are discussed below.

15.1.1 Hydraulic conductivity The hydraulic conductivity (K, with units of velocity—m/s) expresses the ease of movement of water through a soil or rock. For an element of rock volume of area A, perpendicular to the flow, with a difference in hydraulic head h over length L, the quantity of water (Q) that flows through area A in a time interval t is determined by the hydraulic conductivity according to: Q 5 KAht=L

(15.1)

the dimensionless quantity h/L being termed the hydraulic gradient. By comparison with Darcy’s Law (Section 13.2): K 5 kρw g=ηw

(15.2)

where k is the rock or soil permeability, ρw and ηw are the density and viscosity of water, and g is the acceleration due to gravity.

15.1.2 Aquifer storativity and specific yield Storativity (S) is a dimensionless measure of the volume of water that will be discharged from an aquifer per unit area of the aquifer and per unit reduction in hydraulic head. For a confined aquifer, storativity results only from the rock and fluid compressibilities and is typically very small (B1024
1025). For an unconfined aquifer, the small effect of rock and fluid compressibilities is generally neglected, and S is equal to the specific yield (Sy), which is defined as the volume of water that will drain under the force of gravity from unit bulk volume of

Hydrological and environmental features, events, and processes

389

the aquifer. This will be equal to the effective porosity, minus the fractional volume of water retained under gravity drainage by capillary forces. The ratio of hydraulic conductivity to storativity is defined as the hydraulic diffusivity (D, with units m2/s) and is given by: D 5 k=ðCΦηw Þ

(15.3)

where C is the total system compressibility (rock plus fluid) and other quantities are as defined above. Hydraulic diffusivity measures the speed at which a pressure pulse propagates through the aquifer, and high values are desirable in a storage formation as this will reduce the pore pressure buildup in the injection area which in turn will help to maintain the geomechanical integrity of the storage complex and maximize storage capacity.

15.1.3 Regional hydrological regime As previously noted, storage security is increased by any process that increases the gross rock volume swept by the plume of injected CO2, as a result of increased residual trapping, and an active hydrological regime, with a water flow rate that is comparable to the rate of CO2 movement, would be one such process. Such a regime would spread the plume out over a wider area, increasing residual trapping and accelerating solubility and mineral trapping, although this would also necessitate wider areal coverage for monitoring activities. Table 15.1 shows hydrological parameters for a number of regional aquifers which have been well characterized, primarily as a result of hydrocarbon exploitation. In the case of potential host formations that have not had the benefit of this

Table 15.1 Hydraulic gradients and brine velocity in some regional aquifers Formation

Hydraulic gradient range (m/km)

Water velocity range (m/year)

Alberta Basin, Canada

Regional; 0
3 Local; 10
15 0
5

0.01
0.1 0.4
2.0

—

1
30

—

0.2
1.2

0
5

1.0

Waarre Formation, Otway Basin, Victoria, Australia Carrizo-Wilcox aquifer, Gulf Coast Basin, Texas, USA Mt. Simon Sandstone, Illinois Basin, Illinois, USA Midale aquifer, Weyburn, Saskatchewan, Canada

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(A)

(B) Shallow marine

Orogenic belt

Foreland basin

Shelf

Thrust

Continental crust

Sheet

Oceanic crust

Basement

Brines Flow path

(C)

(D) Thic kne

or e

rod

ed

Flow of fresh meteoric water

sed

Flow of deep basin brines

ime

nts

Fau lt

Mountains, thrusted, and folded strata

ss

Basement Basement

Flow path Aquifer Aquitard

Figure 15.2 Basin-scale aquifer flow-driving mechanisms: (A) compaction, (B) tectonic compression, (C) erosional rebound, and (D) gravity. Source: From Bachu (2000), with permission.

kind of appraisal, either due to few well penetrations or not being evaluated in the available wells, a wide range of uncertainty may remain regarding the regional hydrological regime. Processes that result in hydrodynamic flows on a basin scale are illustrated schematically in Figure 15.2. If the hydrodynamic flow is directed downdip, the hydraulic gradient would oppose the updip buoyant movement of injected CO2, a phenomenon known as hydrodynamic trapping. This would slow the migration, increasing the time available for dissolution or, in some cases, might halt or reverse the migration. Assuming a CO2
brine density difference of 500 kg/m3, a hydraulic gradient of 5 m/km would balance the buoyant pressure gradient for a formation dipping at 0.6 degrees (B0.01 radian). Regional hydraulic gradients are therefore likely to have limited impact on plume dynamics—a conclusion confirmed in modeling studies for the Illinois basin—except in near horizontal host formations and for gradients at the top end of the typical range. Once dissolved into formation brine, the forces driving CO2 advection will be gravitational, due to the brine density increase with CO2 dissolution (see Section 13.1), and any hydraulic gradient forcing hydrodynamic water movement.

15.1.4 Vadose and shallow phreatic zone processes The updip section of an open aquifer—in both the vadose zone (unsaturated by groundwater) and the phreatic (saturated) zone—is affected by a variety of natural and anthropogenic hydrological processes such as seasonal or longer term variation

Hydrological and environmental features, events, and processes

391

in recharge rate including inflow from streams, outflow to springs and streams, off-take for human consumption and municipal or industrial use, evaporation and transpiration through surface vegetation, and, in some cases, ocean discharge. These processes will be incorporated into basin-scale models of unconfined aquifers to assess the impact of deep injection of CO2 on shallow potable or near potable resources. Such studies have been undertaken for a number of basins that are potential geological storage sites, notably the Texan Gulf coast, Paris and Illinois basins (see References).

15.2

Geological storage impact on basin-scale hydrology

Impact-scale geological storage will most likely require the implementation of multiple storage projects targeting the most suitable storage complexes within a basin. As a result, site assessment and permitting processes will need to look beyond the impact of individual projects at the potential basin-scale hydrological impacts of multiple storage projects, and the implications for monitoring plans (see Akhurst et al., 2017).

15.2.1 Brine displacement Brine movement, potentially leading to contamination of drinking water resources, can occur by two main mechanisms. Increased pressure in an open storage aquifer may lead to brine migration into updip areas of the host formation containing potable water. If the invading brine is of high salinity, potable water quality could be severely degraded by just a few percent of contamination. Increased pressure in an open or closed storage complex may also cause brine to flow into overlying potable aquifers through conductive paths such as fault planes, abandoned wells or more permeable areas of caprock remote from the CO2 plume. Brine normally immobilized in clays may also be expelled into potable aquifers. There are many natural examples of deep brines migrating into near-surface aquifers in geologically active areas, and the wide range of impacts points to the need for site-specific geochemical modeling where this is considered a significant risk. Basin-scale modeling of large-scale geological storage has shown that the pressure pulse from injection can cause water table rise, reversal of the normal basinward flow direction and shift of isosalinity contours toward the outcrop or other recharge location, potentially causing a salinity increase in water supplied from boreholes, as illustrated schematically in Figure 15.3. Lateral fluid movement far from injection wells may also be mitigated if pressure is relieved by brine migration into a low but non-zero permeability confining formation, as seen for example in regional-scale modeling of Mt. Simon Sandstone in the Illinois Basin and the Sherwood Sandstone in the UK North Sea Basin (see Person et al., 2010; Bricker et al., 2012). Flow into over- and underlying confining

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Carbon Capture and Storage

Aquifer outcrop limit

N

Basinward aquifer recharge

Pre-injection

300 ppm TDS Post-injection 3000 ppm TDS

CO2 plume front CO2 injection wells Downdip aquifer limit

Figure 15.3 Schematic counter-current shift of shallow isosalinity contours due to deep basin CO2 injection.

formations may be very slow—in the order of 5 3 1023 m/year—but volumetrically significant due to the very large flow area (see Equation (15.1)). An important observation from these preliminary basin-scale modeling studies is that the hydrological impact of CO2 injection can be focused and increased locally due to the presence of flow barriers such as shallow fault zones or mitigated due to the properties of hydraulic units connected to the host formation. This emphasizes the need for detailed hydrogeological characterization to address both near-field and far-field effects. In some cases, prediction of the impact of deep injection on shallow groundwater resources may also require the modeling of hydrological processes such as evapotranspiration and aquifer discharge into streams that are not captured in typical subsurface models. Ideally, such assessments should be conducted using calibrated groundwater modeling tools such as those used in water resource management.

15.2.2 Geochemical effects of CO2 in potable aquifers Naturally occurring CO2 in groundwater, typically in the range from 0.1 to 1 wt% depending on temperature and pressure, arises from a variety of biological, geochemical, and geophysical processes, including plant root respiration, oxidation of organic carbon, dissolution of carbonate minerals, and the upward migration of magmatic CO2. The impact of CO2 leakage from a storage complex into an overlying potable aquifer will be dependent on several factors related to the geochemical state of the aquifer, notably the carbonate buffering capacity, the redox state, the presence of heavy metals in the rock mineralogy and also the presence of clay minerals such as illite, kaolinite, and smectite, which have strong adsorption capacities for these contaminants.

Hydrological and environmental features, events, and processes

393

The presence of carbonate or other buffering minerals would limit the initial pH reduction resulting from CO2 dissolution, with the increase in Ca21 concentration potentially driving the release of contaminants via cation exchange and adsorption/ desorption reactions. Once the buffering capacity is exhausted, acidification would result in further mineral dissolution and adsorption/desorption reactions driven by pH reduction. The redox state (i.e., the balance between oxidizing and reducing agents present in the aquifer) is important since some trace metals (e.g., uranium) can be released more easily under oxidizing conditions and others (e.g., arsenic) under reducing conditions. Scavenging of released contaminants by adsorption onto clay surfaces or by deposition of secondary minerals will determine the resulting contaminant concentration in groundwater, and these processes are also affected by pH, redox potential, and other factors. Alongside these inorganic effects, scCO2 is also an effective solvent for a wide range of organic compounds, and increased organic acid and DOC concentrations have been seen in formation waters from saline aquifer injection trials and during EOR operations. CO2 migrating into shallow aquifers therefore also has the potential to mobilize and transport undesirable organic compounds. An assessment of the risk to potable water resources posed by CO2 leakage therefore requires a thorough biogeochemical, mineralogical, and hydrodynamic investigation during site characterization. This may include flow-through column experiments (using core material from the shallow aquifer) as a screening tool to indicate which elements could be mobilized, to determine the key reactions and to constrain the controlling parameters. Such testing will need to cover a sufficiently wide range of samples in order to evaluate the natural variability at relevant scales. Laboratory and in situ release experiments show that, although responses can be complex and highly variable in time and space, existing geochemical modeling techniques can be used to assess the risk of mobilization and determine the maximum contaminant concentrations likely to be reached (see, e.g., Zheng et al., 2009b). Hydrodynamic aspects can be incorporated by coupling detailed geochemical models to coarser basin-scale hydrological models. Other, non-CCS related anthropogenic impacts, such as excessive drawdown leading to brine influx and salinity increase, also need to be considered to put the potential geological storage impact into context and to ensure that any monitoring or remedial requirements are appropriately risk based.

15.3

Hydrological aspects of storage site characterization

An assessment of the hydrological characteristics of hydraulic units that are connected to or may become connected to a potential storage complex will be an essential aspect of site screening and selection.

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Carbon Capture and Storage

15.3.1 Hydrological characterization The initial hydrological characterization of a potential host formation (conductivity, storativity, regional hydraulic regime, etc.) will rely primarily on data collected in existing boreholes, possibly supplemented by evaluation of surface outcrops. Geological interpretations of the structure and stratigraphy, core and formation water sampling and analysis, and downhole pressure measurements, including pressure buildup measurements from pumping tests and/or pressure fall-off from injection tests, will be used to gain an understanding of the hydraulic properties and hydrodynamic behavior, including connectivity and flows (see Wiese, 2010 for an example of hydraulic site characterization at the Ketzin pilot storage site). Static pressure data are typically converted to a hydraulic head at a chosen datum level and displayed as potentiometric contours on a map showing the main structural and stratigraphic elements of the aquifer (faults, pinch-outs, etc.). In this way the hydrodynamic features of the system—such as flow rates and direction, the presence of pressure compartments and their relation to structure (faulting) or stratigraphy— can be visualized. Figure 15.4 shows an extract of this type of analysis for the Waarre Formation in the Otway Basin in Victoria, Australia. As noted above, the properties of the low permeability confining layers (aquitards) within and between permeable aquifers can have a major influence on the far-field

30

30 25 40

35

30 45 25

30

40 35

35

30 35

40 50

35 40 45 35

40

45 35 20

Legend

20

Potentiometric head (m)

30

40 25

Well Fault location Flow path Potentiometric contour

20

50

Figure 15.4 Potentiometric analysis for a segment of the Waarre Formation, Otway Basin. Source: After Hortle et al. (2009).

Hydrological and environmental features, events, and processes

395

response to CO2 injection, and the characterization of these layers over a wide area will be equally important.

15.3.2 Hydrodynamic modeling Construction of geological and fluid dynamic models of the hydrological system connected to a storage formation will be required in order to assess the potential impact of storage operations. These models will not need to be as detailed as those constructed to study plume movement in the host formation, but will need to have an appropriate areal extent in order to assess far-field impacts. The linkage between plume movement and regional hydrodynamic models may be direct, with the finescale model embedded into the larger regional model, or indirect, for example, by specifying boundary conditions (e.g., pressures and/or flow rates) for one model from the other. Regional hydrodynamic models will assume increased importance if several storage projects are in operation or planned that will impact a regional system, and regulatory authorities will have a role to play in ensuring consistency in regional modeling approaches among project operators (see Morris, 2011). If the available pressure data for the hydraulic system shows historical trends in pressure, for example, due to seasonal or longer term environmental changes, or as a result of groundwater extraction or hydrocarbon exploitation, confidence in the hydrodynamic predictions from the model will be increased by history matching the model to fit this data. This will involve adjustment to the model properties affecting hydraulic conductivity, storativity, connectivity (aquitard permeability, fault sealing), etc. Uncertainty management techniques such as single-factor sensitivity analysis and experimental design can be used to quantify the residual uncertainty following this type of model calibration.

15.4

Environmental characteristics and ecosystems

The environmental characteristics that are relevant in assessing impacts that may arise from events in the subsurface are discussed in this section.

15.4.1 Population centers The presence and density of population centers in proximity to an onshore storage site, or above the region of expected plume migration, will be an important factor in determining the potential health, safety, and environmental (HSE) impact of CO2 leakage. In most cases, this will be a site ranking and selection criterion of the first order, not least because of the additional public acceptance challenges that would arise due to such proximity. The potential for leakage into buildings and cellars is well understood from such natural analogues as radon gas buildup. Surface monitoring using gas detection

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Carbon Capture and Storage

equipment can effectively mitigate any HSE risks due to CO2 buildup in buildings, cellars, and other confined spaces. However, while some degree of quantification and risk mitigation may be possible, it is doubtful whether this will be of much relevance to geological storage projects, at least in the near term. Project experience such as that at Shell’s Barendrecht site in the Netherlands suggests that the public debate concerning the siting of geological storage close to population centers is unlikely to hinge on the degree to which risks to the population can be quantified through modeling.

15.4.2 Land use Current and planned land use will be an element in the environmental impact assessment (EIA) of an onshore project. Considerations will include the impact on nearby infrastructure, industrial and agricultural activity as well as the presence of any regulated zones, such as preservation areas or safety zones. A notable example is Chevron’s Gorgon project, discussed further below, where the storage complex is below a nature reserve.

15.4.3 Vegetation and terrestrial fauna The impact of CO2 leakage on surface vegetation and terrestrial fauna is one of several areas where natural analogues provide valuable insights for geological storage operations. Natural CO2 emissions such as those at Horseshoe Lake, Mammoth Mountain in California demonstrate the fatal impact on vegetation of soil-gas CO2 concentrations in the 20%
90% range. High CO2 levels reduce the availability of oxygen which is directly absorbed from the soil by tree roots. At lower levels, shallow subsurface CO2 release experiments have shown an onset of plant stress when the CO2 concentration in soil gas reaches 4%
8% by volume, some three to four times typical background levels (see Chapter 21).

15.4.4 Surface topography Surface topography and meteorology will be dominant factors in determining the fate of injected CO2 that reaches the land surface along natural or man-made leak paths. Natural dispersal due to winds or gravity will prevent the buildup of high CO2 concentrations in the surface environment, except where the surface topography, the built environment or meteorological conditions inhibit dispersal. Natural analogues of topological control of dispersion are well known, with the 1986 Lake Nyos eruption being one of the most catastrophic examples. Dispersion modeling is an essential tool that is used for quantitative risk assessment (QRA) in relation to CO2 transportation risks (e.g., pipeline rupture) and will be equally applicable to the quantification of leakage risks, including the assessment of surface topological effects. Figure 15.5 shows an example of the output from a dispersion modeling study.

Hydrological and environmental features, events, and processes

0.1%

1 m/s

20 Elevation (m)

397

0.2% 0.4%

10 1.5% 1.2%

0.6%

0 0

50

100

150

200

250

Distance (m)

Figure 15.5 Simulated dispersion of a surface CO2 release. Source: After Chow et al. (2009).

The simulation shows contours of CO2 concentration (mass fraction) 15 minutes after the release of 10 t-CO2 at ground level on a surface topology representing gently rolling hills, with a left-to-right wind speed of 1 m/s (Beaufort number 1). The effect of this gentle topology in preventing dispersion is visible on the downwind (right-hand) side of the valley where a downslope flow of CO2 occurs, opposing the mean wind direction.

15.4.5 Surface water bodies Events such as the Lake Nyos disaster in 1986, when a catastrophic degassing event caused the release of an estimated 1.6 Mt of dissolved CO2, demonstrate that leakage of CO2 into surface water bodies can be a significant HSE hazard when the hydrological conditions favor a buildup of dissolved CO2. In the case of Lake Nyos, the stratified nature of the 200 m water column, with lighter, freshwater in the upper 50 m and increasingly dense, saline and CO2-rich water at increasing depth was a determining factor. The 1986 event is believed to have been caused when CO2-rich water was forced up to a depth at which it was supersaturated in dissolved CO2, perhaps as the result of a landslide on the lake shore. The resulting outgassing reduced the hydrostatic pressure of the water column, leading to further outgassing and initiating a chain reaction. The buildup of CO2 in Lake Nyos, which is formed in part of an extinct volcanic crater, is due to the deep inflow of water that has been carbonated through contact with underlying magma. Whether the inflow into a surface water body of CO2 or CO2-rich brine as a result of leakage from an underlying storage complex could result in a similar buildup would depend upon the prevailing hydrological conditions: water composition and properties, location of influx in relation to mixing zones or stratified layers, etc. Monitoring for CO2 inflow would be straightforward, using water sampling and analysis and eddy covariance measurements (see Chapter 19) plus other techniques

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for surface air monitoring. A baseline survey of any surface water bodies in the area that could be affected by migrating CO2 would be conducted prior to the start of injection, with subsequent measurements taking place either as part of the routine monitoring program or contingent on other monitoring observations, such as plume movement toward a fault that poses a risk of migration into a surface water body.

15.4.6 Soils and sediments The impact on soils and soil geochemistry of long-term, low-level CO2 exposure, including typical impurities that would be present in a captured CO2 stream, is an area of active research. Observed impacts include soil anoxia and a reversal of normal negative correlation between soil [O2] and soil moisture content, reduced soil pH as well as changes in mineralogy and trace element presence. An increase in [CO2] in soils (usually accompanied by a reduction in [O2]) and in the deeper subsurface also has the potential to affect microbial activity, with uncertain consequences, as a result of the reduction in soil pH as well as the use of CO2 as an energy source by methanogenic bacteria. Examples of detrimental effects of microbial processes in industrial activity include the acidification of mines as a result of the generation of sulfuric acid due to microbially mediated pyrite oxidation, and the souring of oil reservoirs as a result of H2S generation by sulfatereducing bacteria. Ongoing research projects, including both subsoil release experiments and observations at natural CO2 seeps, demonstrate a complex picture of the potential consequences of long-term CO2 exposure in soils and the shallow subsurface. Plant stress, evident from discoloration and reduced chlorophyll, occurs in some species when soil CO2 exceeds B10% within the root zone, while other species are tolerant to levels up to 40%. In the case of the microbial ecosystem, experiments show little impact at low CO2 while at higher levels (.15%) there is a shift toward anaerobic and acid-tolerant organisms, which may result in an increase in total biomass. Soil and surface gas monitoring is a relatively low-cost monitoring technique that is likely to be an essential monitoring tool for onshore storage. Hyperspectral monitoring of plant stress (see Chapter 19) may be one useful remote sensing tool for leakage detection over wide areas that would be applicable (in the growing season) when a storage site is located below agricultural land. Baseline data for soil CO2 concentration and flux levels may be a requirement for EIA at storage sites, and recent studies suggest that multiyear sampling may be needed to establish a reliable baseline. However, as discussed by Romanak et al. (2012), the concentration ratios of major gases (CO2, N2, O2, CH4) provide signatures of soil processes, such as biological respiration, that can enable the detection of exogenous CO2 without a temporal baseline.

Hydrological and environmental features, events, and processes

15.5

399

Marine environmental aspects

While geological storage in subsea geological formations has the advantage of reducing or eliminating the human health and safety, leakage can still have an impact on the marine ecosystem.

15.5.1 Fate of CO2 leaking from the seabed In water depths shallower than the CO2 buoyancy depth of B2500
3000 m, CO2 leaking from sub-seabed storage would rise through the water column, dissolving into the seawater with residual bubbles dispersing into the atmosphere at the surface. Dissolution will cause local pH reduction and attendant shift in the bicarbonate and carbonate ions concentrations (see Section 10.1) with potential impact on biological processes, over a timescale dependent on the scale of the leak and the local dispersion rate. Dispersion of locally acidified water will occur in the surface mixing zone or as a result of deeper tidal and other currents and would result in outgassing of dissolved CO2 to the atmosphere. Thermal or haline stratification, due to higher surface temperatures or freshwater input from rivers, would slow dispersion and result in more protracted exposure of marine organisms to the effects of reduced pH. At sea temperatures below B9 C and depths below 200
400 m, leaking CO2 bubbles will form gas hydrates which will inhibit dissolution and reduce uptake in the marine environment. Except in the case of catastrophic leakage rates, high concentrations are unlikely to occur under these circumstances. Below the buoyancy depth, scCO2 is heavier than seawater and would remain on the seabed or beneath soft sediments, forming pools in topographical lows. The toxic effects of seabed-ponded scCO2 on fish and other marine fauna have been demonstrated experimentally as part of the investigation into the viability of direct ocean injection as a carbon storage strategy (see Chapter 20).

15.5.2 Recent R&D on marine ecosystem impact While the main focus of operating and proposed CCS demonstration projects in the United States is onshore, in Europe and Australasia the focus is on offshore storage, and this has led to a number of research projects being conducted to assess the potential impact of leakage on the marine environment.

ECO2 project The 4-year EU-funded ECO2 project, tagline “Sub-seabed CO2 storage: Impact on Marine Ecosystems,” was initiated in May 2011 to investigate the likelihood and ecological impact, as well as the economic and legal consequences of leakage from sub seabed storage sites (see Resources). The project generated guidance for project developers on environmental best practice and on monitoring strategies, based on a

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comprehensive program of seabed observations at current storage sites (Sleipner and Snøhvit) and natural seeps in the North Atlantic and Mediterranean, as well as release experiments and modeling studies. The project also conducted studies on the public perception of offshore CCS.

QICS project QICS (Quantifying and monitoring potential ecosystem impacts of geological carbon storage) was a 4-year project funded by the UK National Environmental Research Council that ran from 2010 to 2014. The project used a novel release experiment that mimicked leakage from sub seabed storage by injecting CO2 into seabed sediments in order to assess the impact on the marine ecosystem and to determine the best methods for leakage detection and impact monitoring in the marine context. A total of 4.2 t-CO2 was injected over a 37 day period, at a depth of 11 m into the seabed sediment. The general conclusions of the QICS project, which are documented in detail on the project web site and in a special issue of the International Journal of Greenhouse Gas Control (see Resources), were that the ecological impact of smallscale leakage would not be significant although leakage on a larger scale, while considered very unlikely, could have a more significant local impact. The studies also concluded that, although challenging due to the complexity and natural variability of the response, detection and impact monitoring of small-scale leakage would be possible given further development of current tools. Other modeling studies of CO2 leakage in the North Sea concluded that the largest conceivable leaks (in the order of 10 kt-CO2/day for a year) would have a significant environmental impact (a harmful ΔpH . 1, c.f. natural variability of 60.2) over large spatial scales (tens of km).

15.6

EIA process

The features, events, and processes relating to the subsurface, terrestrial and marine environments that might be impacted by leakage of CO2 from the storage complex will be important inputs to the EIA and to the QRA studies of any storage project. Table 15.2 summarizes the main environmental impacts arising from subsurface causes that have been largely discussed in the previous section. Preparation, submission, and consultation on the EIA or environmental impact statement will be a major part of the permitting process for any geological storage project. Figure 15.6 illustrates schematically the EIA process. The process begins with the identification of hazards and threats (also known as stressors—sources or situations with the potential to cause harm or other adverse effects), often in a hazard identification (HAZID) workshop. Receptors are the ecological entities, such as faunal communities and habitats, that may suffer adverse effects due to exposure to the hazards and threats. The primary stressor in relation

Hydrological and environmental features, events, and processes

401

Table 15.2 Summary of the main potential environmental impacts for a geological storage project Impact

Description

Health and safety of human population

Potential HSE implications of surface emission of CO2 as a result of leakage from the storage complex. Factors such as the location of population centers, surface topology, and dispersion modeling will play a role in the assessment Groundwater and surface water quality Potential impact on potable water quality as a result of mobilization of heavy metals in groundwater; potential for CO2 buildup and subsequent release from surface water bodies. Shallow aquifer mineralogy and the hydrological and chemical conditions in water bodies will be the important factors in assessing these risks Abundance and distribution of floral and Potential impact of CO2 leakage on flora and faunal communities; biodiversity fauna in the terrestrial or marine environments, as well as the impact on subsurface microbial populations

to the subsurface aspects of geological storage is the release of CO2 from the storage complex, and Table 15.3 lists the related potential receptors. The consequence criteria in the table would be used in defining the scale of consequences that a hazard can have on a receptor (note that a risk is specified in terms of a consequence times a likelihood). For example, Table 15.4 shows the consequence scale for the impact on the populations levels of protected fauna as adopted by the Chevron-operated Gorgon project, which commenced production in 2016 and in which B2.7 Mt-CO2/year recovered from natural gas treatment (14% CO2) is being injected into the Dupuy formation, a saline aquifer some 2 km below Barrow Island, 60 km off the northwest coast of Western Australia. Determination of the likelihood of each consequence occurring, in consultation with ecological specialists, will allow each risk to be placed in a risk assessment matrix (RAM), where probability of occurrence is plotted for each risk against the potential severity of the consequence. A generic RAM is shown in Figure 15.7, including the likelihood definitions as used in the Gorgon project EIA. A risk-based Environmental Management Plan would then be developed, typically focusing on those items classified as high and medium risk, with the aim of reducing risk to an acceptable level. Baseline studies and subsequent environmental monitoring will be an integral part of the management plan, to provide assurance of its effectiveness or to initiate corrective actions.

Consultation

Scoping

Observation

Establish agreed methodology: define consequences and likelihood criteria, establish risk matrix Identify stressors and receptors

Communicate

Conduct

Risk assessment

and consult

baseline

with ecological

Determine likelihood

specialists and

Analyze risks

Determine consequences

stakeholders

studies and monitoring programs

Evaluate and characterize risks

Implementation Execute environmental management plan

Figure 15.6 Schematic EIA process. Source: After Chevron—Gorgon Project (2005).

Hydrological and environmental features, events, and processes

403

Table 15.3 Potential receptors and consequence criteria in relation to leakage of CO2 from the storage complex Receptors

Consequence criteria

Terrestrial environment Soils Surface and groundwater Protected and general fauna Restricted and general flora and vegetation communities Subterranean fauna

Soil contamination Water quality Species behavior; population size and viability Species or community abundance or distribution Species behavior; population size and viability

Marine environment Seabed Benthic primary producers and significant communities General floral taxa and communities Listed species or evolutionary significant units General faunal species and communities

Sediment contamination Species or community abundance or distribution Species or community abundance or distribution Species behavior; population size and viability Species behavior; population size and viability

Source: After Chevron—Gorgon Project (2005).

Table 15.4 Consequence scale for population effects on protected fauna species Consequence category

Consequence

Minor

Local, short-term decrease in abundance. No lasting effects on local population Local, long-term or widespread, short-term decrease in abundance Loss of small number of individuals without reduction in local population viability Local, long-term or widespread, short-term decrease in abundance Loss of individuals leads to reduction in viability of local population No reduction in viability of race on Barrow Island Local, long-term or widespread, short-term impact leads to loss of local population(s) and reduced viability of the race on Barrow Island Widespread, long-term impact on population. Extinction of Barrow Island race

Moderate

Serious

Major Critical

Source: After Chevron—Gorgon Project (2005).

Consequence category

Likelihood category

Description

Almost certain

Very likely to occur on an annual basis. Includes planned activities

Likely

Likely to occur more than once during the life of the proposed project

Possible

May occur during the life of the proposed project

Unlikely

Not likely to occur during the life of the proposed project

Remote

Highly unlikely and unheard of in industry, but theoretically possible

Minor

Moderate

Serious

Major

High risk

Medium risk

Low risk

Figure 15.7 Risk assessment matrix. Source: After Chevron—Gorgon Project (2005).

Critical

Hydrological and environmental features, events, and processes

15.7

405

References and resources

15.7.1 References Akhurst, M.C., Mallows, T., Pearce, J.M., Mackay, E., 2017. Assessing interactions between multiple geological CO2 storage sites to optimise capacity in regionally extensive storage sandstones. Energy Procedia. 114, 4571
4582. Bachu, S., 2000. Sequestration of CO2 in geological media: criteria and approach for site selection in response to climate change. Energy Convers. Manage. 41, 953
970. Birkholzer, J.T., Zhou, Q., 2009. Basin-scale hydrogeologic impacts of CO2 storage: capacity and regulatory implications. Int. J. Greenhouse Gas Control. 3, 745
756. Brewer, P.G., et al., 2006. Three-dimensional acoustic monitoring and modeling of a deepsea CO2 droplet cloud. Geophys. Res. Lett. 33 (L23607). Bricker, S.H., Barkwith, A., MacDonald, A.M., Hughes, A.G., Smith, M., 2012. Effects of CO2 injection on shallow groundwater resources: a hypothetical case study in the Sherwood Sandstone aquifer, UK. Int. J. Greenhouse Gas Control. 11, 337
348. Chevron—Gorgon Project, 2005. Environmental Impact Statement/Environmental Review and Management Programme for the Gorgon Development. Chevron Australia. Chow, F.K., Granvold, P.W., Oldenburg, C.M., 2009. Modeling the effects of topography and wind on atmospheric dispersion of CO2 surface leakage at geologic carbon sequestration sites. Energy Procedia. 1, 1925
1932. Hortle, A., Xu, J., Dance, T., 2009. Hydrodynamic interpretation of the Waarre Fm Aquifer in the onshore Otway Basin: implications for the CO2CRC Otway Project. Energy Procedia. 1, 2895
2902. Jones, D.G., et al., 2015. Developments since 2005 in understanding potential environmental impacts of CO2 leakage from geological storage. Int. J. Greenhouse Gas Control. 40, 350
377. Lions, J., et al., 2014. Potential impacts of leakage from CO2 geological storage on geochemical processes controlling fresh groundwater quality: a review. Int. J. Greenhouse Gas Control. 22, 165
175. Little, M.G., Jackson, R.B., 2010. Potential impacts of leakage from deep CO2 geosequestration on overlying freshwater aquifers. Environ. Sci. Technol. 44, 9225
9232. Morris, J.P., Detwiler, R.L., Friedmann, S.J., Vorobiev, O.Y., Hao, Y., 2011. The large-scale geomechanical and hydrogeological effects of multiple CO2 injection sites on formation stability. Int. J. Greenhouse Gas Control. 5, 69
74. Nicot, J.-P., 2008. Evaluation of large-scale CO2 storage on fresh-water sections of aquifers: an example from the Texas Gulf Coast Basin. Int. J. Greenhouse Gas Control. 2, 582
593. Nicot, J.-P., Hovorka, S.D., Choi, J.-W., 2009. Investigation of water displacement following large CO2 sequestration operations. Energy Procedia. 1, 4411
4418. Person, M., et al., 2010. Assessment of basin-scale hydrologic impacts of CO2 sequestration, Illinois Basin. Int. J. Greenhouse Gas Control. 4, 840
854. Romanak, K.D., Bennett, P.C., Yang, C., Hovorka, S.D., 2012. Process-based approach to CO2 leakage detection by vadose zone gas monitoring at geologic CO2 storage sites. Geophys. Res. Lett. 39, L15405. Rostron, B., Whittaker, S., 2011. 101 years of the IEA-GHG Weyburn-Midale CO2 monitoring and storage project: successes and lessons learned from multiple hydrogeological investigations. Energy Procedia. 4, 3636
3643.

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West, J.M., McKinley, I.G., Palumbo-Roe, B., Rochelle, C.A., 2011. Potential impact of CO2 storage on subsurface microbial ecosystems and implications for groundwater quality. Energy Procedia. 4, 3163
3170. Wiese, B., Bo¨hner, J., Enachescu, C., Wu¨rdemann, H., Zimmermann, G., 2010. Hydraulic characterisation of the Stuttgart formation at the pilot test site for CO2 storage, Ketzin, Germany. Int. J. Greenhouse Gas Control. 4, 960
971. Zheng, L., Apps, J.A., Zhang, Y., Xu, T., Birkholzer, J.T., 2009a. Reactive transport simulations to study groundwater quality changes in response to CO2 leakage from deep geological storage. Energy Procedia. 1, 1877
1894. Zheng, L., Apps, J.A., Zhang, Y., Xu, T., Birkholzer, J.T., 2009b. On mobilization of lead and arsenic in groundwater in response to CO2 leakage from deep geological storage. Chem. Geol. 268, 281
297.

15.7.2 Resources

CCS and the Marine Environment, Special issue of the International Journal of Greenhouse Gas Control (Volume 38, July 2015) Open Access (Blackford, J., Stahl, H., Kita, J., Sato, T. (Eds.)). ECO2—Sub-seabed CO2 storage: impact on marine ecosystems. Project web site www.eco2project.eu/about-eco2.html. See also Best Practice Guidance for Environmental Risk Assessment for Offshore CO2 Geological Storage, available from the ECO2 project web site. Energy Alberta. Carbon capture & storage—summary report of the regulatory framework assessment. Available at www.energy.alberta.ca. European Union, 2009. Directive 2009/31/EC on the geological storage of carbon dioxide. Available at http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri5CELEX:32009 L0031&from5EN ISO (International Standards Organization), 2004. ISO 14001:2004 Environmental management systems—requirements with guidance for use. International Standards Organization, Geneva, Switzerland. NETL (National Energy Technology Laboratory), 2002. Lessons learned from natural and industrial analogues for storage of carbon dioxide in deep geological formations. National Energy Technology Laboratory, Report LBNL #51170. QICS—Subsea CO2 release and monitoring experiments: www.bgs.ac.uk/qics. Shell UK Limited, 2014. Peterhead CCS Project Offshore Environmental Statement. Available at https://s02.static-shell.com/content/dam/shell-new/local/country/gbr/downloads/ pdf/upstream/peterhead-ccs-scoping-report.pdf. STEMM-CCS—EU-funded project developing tools and techniques for CO2 emission monitoring and quantification from sub-seabed storage: www.stemm-ccs.eu.

Engineered system features, events, and processes

16

The full engineered system for a geological storage project includes capture and transportation systems, surface facilities at the injection site, and subsurface components—namely, the injection, production, and monitoring wells and associated hardware. This chapter describes the design, construction, operation, and maintenance, and eventual abandonment of the subsurface engineered system, which plays an important part in the success of a geological storage project.

16.1

Well construction and status

The primary objective in well design and construction is to provide a conduit to enable injection of fluids into or production from a target formation at a desired rate, while the secondary objective is to ensure that competent barriers are installed to prevent any unwanted communication either between different subsurface formations (zonal isolation) or to the surface.

16.1.1 Well design Well design proceeds in two stages: the functional requirements of the well being first specified, following which the well construction details to deliver those functional requirements can be defined. Many aspects of well design are dictated by regulatory requirements, an example being the US Class VI regulations which apply to CO2 storage wells. Typical contents of the three main design documents for a well—the Functional Specification, Drilling, and Completion Programs—are summarized in Table 16.1. In oil and gas field practice, a well design life of around 25 years is either specified or commonly assumed for materials selection purposes. While this may be appropriate for some wells in a geological storage context (e.g., remote monitoring wells that are not expected to be exposed to the CO2 plume), the design life for CO2 injection wells may be significantly longer, requiring particular attention to be paid to well construction quality and material selection.

16.1.2 Well drilling and casing Well construction starts with the drilling of a surface hole, typically 0.76 m (30v) or 0.91 m (36v) in diameter using a rotary drilling bit on the end of a string of steel drill pipes. Rock cuttings are lifted out of the well by circulating a viscosified fluid known as drilling mud down through the drill pipe, out of the bit and up the annulus Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00016-7 © 2017 Elsevier Inc. All rights reserved.

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Table 16.1 Typical contents of well design documents Document

Contents

Functional specification

Target formation(s) and geological prognosis Subsurface target location(s) and tolerances Fluid pressure and formation strength prognoses Expected injectivity and injection rate Evaluation program (logging, coring, sampling)

Drilling program

Planned hole and casing sizes, and setting depths Required drilling mud properties (weight, viscosity, etc.) Planned well trajectory and directional drilling requirements Cement recipes and job specifications (rate, volume, etc.) Hole cleaning requirements prior to completion

Completion program

Hardware design for lower and upper completions Material specification for all completion components Completion procedures

around the drill pipe. The drilling mud is prepared using suitable weighting material (such as barite) to ensure that the hydrostatic head of the mud column up to surface exceeds the expected pore pressure of all formations that will be encountered in a particular hole section. This mud pressure overbalance is the first well control “barrier” that prevents the ingress of formation fluids into the wellbore. When the drilling bit reaches a permeable formation, the drilling mud is designed such that it will form an impermeable layer on the borehole wall, known as the mud filter cake, as a result of fluid expulsion into the formation under differential pressure. This filter cake prevents further fluid loss into the formation, which is important to limit potential damage to the formation and to ensure that electrical and other well logging measurements are influenced by the original formation fluids and not by invaded mud filtrate. If the formation is particularly sensitive to damage due to drilling fluid ingress, the technique known as underbalanced drilling can be applied to prevent this damage. In this case the mud weight is reduced when the target formation is drilled, deliberately allowing the ingress of formation fluid. Pressure control equipment is installed at the wellhead to maintain control on well pressure and flow rate. When drilling of a hole section has reached the required depth and all cuttings have been removed, a steel casing is constructed from threaded B10 m long joints and lowered into the well. The casing is typically 5 to 10 cm smaller in diameter than the drilled hole size and is cemented into the rock by pumping cement down the inside of the casing and displacing it up the annulus, as described in the following section. This process of drilling and casing, illustrated in Figure 16.1, is repeated a number of times with progressively smaller drill bit and casing diameters, until the target formation is reached and a final casing is set. This final casing often extends only up to the bottom (or “shoe”) of the previous casing and not all the way to surface, in which case it is known as a liner rather than a full casing string. If the well has an appraisal objective (e.g., a well drilled for site characterization), the final hole section may be abandoned after data gathering, without setting a casing or liner.

Engineered system features, events, and processes

409

Figure 16.1 Drilling and casing a hole section.

Figure 16.2 Well construction configurations.

The well construction geometry can be varied depending on the specific well objectives, as illustrated in Figure 16.2. Where surface access is unimpeded, vertical wells are the cheapest option, while deviated, horizontal and multilateral wells can be drilled to overcome surface and subsurface constraints, or to increase well productivity or injectivity as a result of a larger contact area with the target formation. A horizontal injection well is used in Statoil’s Sleipner project to inject CO2 into the Utsira aquifer beneath the Norwegian sector of the North Sea, in view of the need to displace the point of injection away from the deeper gas production wells, while vertical wells have been used in projects such as In Salah, Algeria, where surface access is unimpeded in the desert environment.

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16.1.3 Well cementation Cementation of a casing string or liner into the borehole (known as primary cementation) is a critical activity to ensure the integrity of the well and avoid unwanted fluid movements behind the casing, either between zones (zonal isolation) or, in the worst case, to surface. The design of the cementing job, which is an integral part of the well planning and design process, will be reviewed and finalized once the hole section has been drilled and the bottom-hole temperature and pressure as well as the required volume of cement can be determined—the latter using caliper log data to assess the geometry of the open-hole section. A cement “recipe” is designed to achieve the required slurry viscosity, setting time and cement strength, and the recipe is lab tested before the cementing job, under simulated in situ conditions, to ensure that the desired properties are achieved. In the cementing operation, a pre-flush is pumped to remove the drilling mud filter cake from the borehole wall, followed by the cement slurry. Once the required cement volume has been pumped, a mechanical plug is pumped down the casing until it locks into a seat that has been installed at the shoe of the casing, displacing the cement out of the casing and into the annular space. The cement is now in place across the desired interval outside the casing, and the well is left for the period required to allow the cement to set. It is particularly important that no operations take place on the well during this period that alter the internal fluid pressure, as the resulting casing strain can compromise the bond between casing and cement, resulting in a vertical communication path outside the casing. Common operating practices to ensure a good bond between the cement sheath and both the casing and the formation include: G

G

G

G

G

Good hole cleaning, mud and cuttings removal, and pre-flushing with a chemical wash to remove mud filter cake Pump rate selection to achieve the desired cement flow regime Centralizing the casing in the borehole using adequate centralizers to ensure even circumferential hole cleaning and cement placement Rotating or reciprocating the casing during the pumping of cement to improve surface contact Preventing mechanical or pressure shocks during cement setting to ensure that the partially set slurry does not debond, leading to the formation of a microannular flow path.

In cementing oil and gas wells, it is not common practice to completely fill the annular space outside each casing strings with cement. Typically the top of cement for any casing will be 100
200 m inside the shoe of the previous casing. This practice reduces well construction costs, allows the shallow part of each casing to be recovered during well abandonment and, if hydrocarbons do leak behind the casing, the larger annular volume enables early detection without excessive pressure buildup. For CO2 injection and monitoring wells it is likely that these considerations will be outweighed by the overriding requirement to eliminate potential leak paths, so that well designs will include the cementation to surface of all casing strings. For

Engineered system features, events, and processes

411

example, the US EPA requirements for Class VI wells (see US EPA, 2010) require that surface casing is set through the base of the deepest USDW and cemented to the surface. Deeper casings are also required to be cemented to surface, although operators are given leave under the Final Rule to apply for a waiver provided that additional safeguards are in place to protect USDW. Once the cement has set, the quality of the bonds to the casing and formation, uniformity of the cement sheath, and strength of the cement can be assessed using downhole logging tools (cement bond logging or cement evaluation tools). Figure 16.3 shows an example of a suite of cement evaluation log results. From left to right, the log shows the amplitude (AMP and AMP 20, in mV) of the acoustic signal transmitted along the casing, the relative amplitude (%), a variable density log (VDL) which displays the amplitude of the first millisecond of the received waveform, and a variable amplitude density map which shows an azimuthal map of the relative cement strength around the welbore. The top of cement at 790 m is clearly seen by an increase in the AMP signal to B15
25 mV and by the casing “ringing” in the VDL display. The casing material changes from steel to glass-reinforced epoxy (GRE) at 950 m and this is also evident from the AMP log. In extreme cases a poor cement job can be remediated using a squeeze cementation, which involves the perforation of one or more holes into the casing string, using explosive shaped charges, and the squeezing or circulation of cement into the annular space. This type of cementing job, known as a secondary cementation, has a relatively low rate of success in oil field practice, with the added complication of needing to seal the through-casing flow paths created by the perforations.

Figure 16.3 Cement evaluation logging tool results. Source: From Nakajima et al. (2013), with permission.

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Carbon Capture and Storage

Types and composition of well construction cement The cement used in well construction is typically a Portland cement based product, the main ingredients being di- and tri-calcium silicates (2CaO  SiO2 and 3CaO  SiO2), which constitute at least two-thirds of the cement clinker mass, along with other iron and aluminum containing compounds which are products of the calcining process (see Chapter 5). A range of different cement types are defined by the American Petroleum Institute (API) classification for use under different temperature and pressure regimes, as summarized in Table 16.2.

Table 16.2 Main characteristics of API cement classes API class

Typical depth range

Description

A

0
1830 m (0
6000 ft) 0
1830 m (0
6000 ft)

Ordinary (O) grade cement used at shallow depths when there are no special requirements Sulfate-resistant cement, available in moderate (MSR) and high (HSR) sulfate-resistant grades, to prevent cement deterioration due to sulfate in formation water A rapid hardening cement that delivers high early strength during the setting process; available in O, MSR, and HSR grades. Depth range can be extended to 3050 m (10,000 ft) using additives Moderate temperature and pressure cement, containing chemical retarders and available in MSR and HSR grades; coarse particle size requires a lower water to cement ratio High temperature and pressure cement, containing chemical retarders and available in MSR and HSR grades; coarse particle size requires a lower water to cement ratio Extremely high temperature and pressure cement, containing chemical retarders and available in MSR and HSR grades; coarse particle size requires a lower water to cement ratio Basic well cement; available in MSR and HSR grades. Depth range can be extended through the use of additives Basic well cement; available in MSR and HSR grades. Depth range can be extended through the use of additives Cement for very high temperature and pressure applications

B

C

0
1830 m (0
6000 ft)

D

1830
3050 m (6000
10,000 ft)

E

3050
4270 m (10,000
14,000 ft)

F

3050
4880 m (10,000
16,000 ft)

G

0
2440 m (0
8000 ft) 0
2440 m (0
8000 ft) 3660
4880 m (12,000
16,000 ft)

H J

Engineered system features, events, and processes

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Portland cement additives A variety of additives are used in well cementation to control the properties of the cement slurry (such as fluid loss, density, and viscosity), the setting process (setting time at a specific downhole temperature), and the properties of the set cement (compressive strength, chemical resistance, etc.). The main types of cement additives are summarized in Table 16.3.

Non-Portland cement for CO2 service In constructing wells for CO2 service, Portland cement additives such as those outlined above can be included in the cement recipe to substantially reduce the rate of reaction with CO2. A number of alternatives to Portland cement are also commercially available that do not react with CO2, including materials based on calcium sulfoaluminates (Ca4(AlO2)6SO4), alkali aluminosilicates (geopolymer), and magnesium oxide as well as hydrocarbon-based cements. Extensive field experience has been gained in the use of these cements in acid gas injection wells, while R&D efforts continue to identify and test alternative cement additives for CO2 service (see, e.g., Baldissera et al., 2017). Recently self-healing (so-called “smart”) cements have also been developed for CO2 service, which contain additives such as latex that swell on contact with CO2 (see Mosleh et al., 2017). These cements are particularly designed for use in wellbore leakage remediation but could also be used in critical hole sections, such as the caprock penetration or across shallow aquifers, during initial well construction.

16.1.4 Data gathering in wells The construction of a well provides an opportunity to gather data on the subsurface formations penetrated by the bit, both the target formation and those in the shallower sections of the well—the overburden. Once wells are in service, either for production or injection, additional data can be gathered from instruments permanently installed in the well or by running instruments into the well to conduct surveys. The types of data that can be acquired are summarized in Tables 16.4 and 16.5 for the construction and operating phases, respectively.

16.1.5 Well completion and control After the well has been drilled and the final casing or liner run and cemented, the rig operation switches from drilling to completions, an important difference being the cleanliness of the operation and of the fluids and materials pumped or run into the well. This is particularly important for injection wells, since the final fluid and any loose particles left in the well will be injected into the formation when the well is started up, and could impair injectivity. Cleaning of hardware such as the tubing string and filtration of all fluids used during the operations are therefore important aspects of the completion phase.

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Table 16.3 Main types of Portland cement additives Parameter

Description

Setting time

Setting time can be adjusted using accelerators (CaCl, NaCl, KCl) or retarders (cellulose, calcium lignosulfonate), while retarders can also be used to extend the application of a cement to higher temperatures and pressures Gel strength Gel strength modifiers are used to shorten the transition period between modifiers slurry and set cement conditions, during which the cement column no longer exerts hydrostatic pressure and fluids, particularly gas, can enter the cement Slurry density Weighting materials (barite, sand, hematite) are used to increase the cement slurry density in order to achieve the required hydrostatic pressure in the cement column, while density reduction materials, also known as cement extenders (pozzolans, bentonite), may be used to reduce the slurry density to avoid fracturing the formation. The use of nitrogen in foam cement is an extreme example of density reduction Slurry viscosity Slurry viscosity is typically reduced, to enable pumping at higher rates and lower circulating pressures, by the addition of viscosity reduction additives (dispersants) such as NaCl and calcium lignosulfonate (see also setting time effects) Fluid loss Loss of filtrate from the cement into porous rocks (after removal of the mud filter cake) can be reduced by using fluid loss control additives, such as the water-soluble polymer hydroxy-ethylcellulose Cement Reducing the permeability of the cement sheath reduces its susceptibility permeability to CO2 degradation (see Section 16.2.1). This can be achieved by increasing the cement to water ratio in the slurry or by the addition of pore filling particles, including synthetic fibers Cement volume Cements can be made to expand slightly after setting to improve the bond to casing and formation using additives such as gypsum that promote the formation of compounds with a higher molar volume Cement elasticity The elasticity of the cement sheath and its resistance to stress changes due to pressure and temperature cycling or formation deformation due to uplift can be reduced by the addition of elastomers (latex) and synthetic fibers (polypropylene and nylon) Chemical A wide range of additives affect chemical susceptibility; e.g., calcium resistance aluminate, used to extend the temperature range and latex, used to improve bonding, cement elasticity and filtration properties, both reduce susceptibility to cement corrosion by carbonic acid

A well completion consists of two parts: the sandface completion, providing the interface between the reservoir rock and the wellbore and the upper completion, comprising equipment installed within the last casing string to control and monitor the well flow and ensure well safety.

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Table 16.4 Data gathering during well construction Data gathering technique

Description

Data types

Open-hole logging

Lowering of measuring sondes into the borehole either on an electrical cable (wireline logging) or as an integral part of the drill string (logging while drilling) Cutting of rock samples either from the wall of an already drilled hole (side-wall coring) or while drilling using a special coring drill bit and core collection barrel

Radioactivity, density, and porosity inferred from nuclear measurements, acoustic velocity, electrical resistivity, nuclear magnetic resonance response Grain size distribution and mineralogy, radioactivity, rock strength, porosity and permeability by laboratory analysis, fluid content, relative permeability, and capillary pressure behavior Formation pressure and permeability, recovery of fluid samples, downhole analysis of fluid composition High-resolution seismic data

Coring

Formation fluid sampling

Lowering a fluid sampling tool into the well on wireline or as part of the drill string

Vertical seismic profile logging

Use of downhole geophones and surface-induced vibrations to generate high-resolution seismic data for the formations near the wellbore

Table 16.5 Data gathering during well operations Data gathering technique

Description

Data types

Cased-hole logging

Lowering of measuring sondes into the cased hole on an electrical cable (wireline logging) or on coiled steel tubing during a well intervention

Fluid density and flow rate, static and flowing temperature profiles, and several of the open-hole data types (radioactivity, density and porosity inferred from nuclear measurements, nuclear magnetic resonance response) Static and flowing pressure, spot temperatures, and full well temperature profile

Installation of instrumentation as Permanent part of the well completion to downhole allow continuous well and instrumentation reservoir performance monitoring

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Figure 16.4 Types of sandface completion.

The sandface completion is required to protect the well from the ingress of formation material should the rock fail under production or injection conditions. Rock strength measurements on core samples, the planned well geometry (particularly the deviation from vertical), and production or injection pressures and flow rates are used to decide on the appropriate sandface completion type. For the most competent rock, the bottom part of the well may be left uncased, resulting in an open-hole completion (Figure 16.4). The most common completion is a “cased and perforated” completion, in which many holes or perforations, typically 1
2 cm in diameter and 0.40
0.60 m in length are shot through the final casing and surrounding cement using explosive shaped charges mounted in a perforating gun. Formations that are at risk of mechanical failure under production or injection conditions are completed using screens or gravel packs, in order to prevent the ingress of failed formation material into the wellbore. The upper completion comprises a number of components as illustrated in Figure 16.5. A tubing string contains the production or injection flow and, together with the production packer, protects the inner casing from corrosion. Mechanically operated sleeves or electrohydraulic control valves may be installed together with additional packers to allow operational control over which formations are open for production or injection. Close to the surface, a safety valve is installed in the tubing string to prevent the escape of fluids from the tubing and reservoir in the event of loss of the surface containment barriers, for example, due to damage to surface equipment. At surface, the well is capped by a so-called “xmas tree” which houses a master control valve and other valves to control production and access to and monitoring of the various tubing and annular spaces. Electrical and hydraulic connections through the body of the tree provide for downhole control and monitoring signals. Selection of suitable materials is an important aspect of well and completion design, with corrosion resistance being a key design factor (see Parker, 2009). This

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Figure 16.5 Upper completion components.

in turn depends on the nature of the produced or injected fluids, and will be an important consideration in wells for CO2 service, especially if there is a risk of free water presence resulting in carbonic acid corrosion.

Monitoring (observation) well construction The design and construction of monitoring wells will reflect both the general requirements for any well that will be exposed to the CO2 plume and the specific requirements of the monitoring program. Particular attention will need to be given to: G

G

G

The use of materials, including cement, suitable for extended CO2 exposure High-quality cementation through the storage complex and overburden formations Provisions for effective abandonment during site closure

Specific well construction requirements for monitoring may include: G

Use of special materials for casing/liner and other components (e.g., GRE) to enable through casing monitoring

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Figure 16.6 Ketzin carbon capture and storage (CCS) pilot project; injection and monitoring well configurations. Source: From Prevedel et al. (2014), with permission.

G

G

Installation of downhole instrumentation, such as discrete point pressure and temperature (PT) gauges, distributed temperature sensors (DTS), geophones for seismic monitoring, electrodes for resistivity logging or cross-well tomography (VERA—vertical electrical resistivity array), etc. Completion hardware, such as fluid sampling ports, to enable periodic sampling of nearwellbore fluid

Fluid sampling ports based on a U-tube design (see Freifeld, 2009) have been successfully applied in a number of geological storage pilot project monitoring wells, including the Frio Brine Pilot and the CO2CRC Otway project. Further details on monitoring technologies can be found in Chapter 19. Figure 16.6 shows the well configurations used in the Ketzin CCS pilot project in Germany and illustrates a number of design features discussed above, including partially cemented and GRE casing strings, various sandface completion types (open hole, cased and perforated, slotted screens) and monitoring functions (PT, DTS, VERA, U-tube sampling).

16.1.6 Well operations The operational life of a new well begins with the execution of a start-up procedure, which specifies the gradual ramp-up of production or injection rate and associated monitoring to ensure that the well is performing in line with expectations. Considering an injection well, rates and pressures observed during start-up will

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Table 16.6 Factors affecting well injectivity Factor

Description and possible impact

Clean-up

Gradual or abrupt increase in injectivity early in the well life due to the clean-up of the sandface, for example, as a result of the removal of residual mud filter cake Gradual or abrupt decrease in injectivity at any stage in the well life as a result of permeability loss in the near-wellbore region due to injection or precipitation of fine pore plugging material (e.g., formation drying and halite deposition) or formation alteration due to fluid incompatibility Abrupt increase in injectivity as a result of fracturing of the formation, either due to injection above the fracturing pressure or a change in the stress regime (and reduction in rock strength) due to cooling of the formation Gradual changes in injectivity due to the effect of changing wetting and non-wetting phase saturations on relative permeability in the nearwellbore region

Impairment

Fracturing

Relative permeability

indicate whether the required injectivity has been achieved or whether the injection plan needs to be adjusted in line with actual injection performance. The injectivity of a well is rarely constant throughout its life and may be affected by a range of factors, as summarized in Table 16.6. Once the baseline performance of an injection well has been established, the range of allowable operating conditions—known as the operating envelope—will be specified to guide operational staff. This will include the target injection rate and wellhead or bottom-hole pressure, the maximum allowable injection pressure, the maximum allowable pressure in the annulus surrounding the tubing (known as the “A” annulus) and in each successive annulus (B, C, etc.). For monitoring wells, operational procedures for periodic data gathering will also be required. In the operation of CO2 wells, shut-in and depressurization events need specific procedures, particularly in the presence of water when there is a risk of hydrate formation. While experience in these issues is being gained in the currently operating storage and EOR projects, this is also the topic of ongoing experimental investigation in a test well constructed at the Statoil Research Center in Trondheim, Norway.

16.1.7 Well abandonment The abandonment of a well at the end of its service life, which may be immediately after drilling and evaluation in the case of an appraisal well, typically involves the placement of a number of cement plugs inside the well, as illustrated in Figure 16.7. The number, position, and length of cement plugs will be defined in a well abandonment program, taking account of regulatory requirements and well

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Figure 16.7 Example of well abandonment configuration.

specific conditions—such as the geology, and well drilling and operating history— to identify locations with greater corrosion risk. Regulatory requirements in various legislatures specify the minimum required length of cement plugs for well abandonment varying from 15 to 100 m. As discussed in the next section, the very low experimentally observed rates of cement degradation by aqueous CO2 (,1 m in 10,000 years) mean that plug lengths based on current practice do not need to increase for CO2 service, and the quality of placement and mechanical integrity of cement plugs will be the primary focus of abandonment operations. Open perforations may first be sealed using a squeeze cementation, in which a specially designed cement slurry is squeezed through the perforations to seal the perforations and adjacent sandface. Cement plugs placed within the wellbore may either be balanced plugs, with a density close to the surrounding fluid, or placed on top of mechanically set bridge plugs. Uncemented casing strings may be cut and retrieved, either to salvage materials or to enable more effective placement of cement plugs, although casing removal is unlikely for CO2 injection wells in the United States, given the Class VI cementation requirements noted above. Finally, the surface equipment is retrieved and the wellhead is capped with a welded plate or flanged seal. The abandonment of any wells located within the region swept or expected to be swept by the CO2 plume will be particularly important in order to mitigate the risk of leakage through these engineered conduits. Traditional cement plug practices can eliminate leakage risk within the well, but if there is uncertainty about the competence of the external cement sheath at critical locations, the abandonment will need

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Figure 16.8 Pancake cement plug to address annular leakage risk.

to address this. Figure 16.8 illustrates one remediation method—the pancake cement plug—that can be applied in this situation. Placement of such a cement plug requires the milling of a window in the casing, drilling out of the existing cement sheath, and widening of the borehole using a special extending drill bit in an operation known as under-reaming. This exposes a fresh formation surface and increases the chance of achieving an effective seal.

16.2

Processes affecting well integrity

Well integrity refers to the competence of the barriers that prevent unwanted communication between different intervals, namely, the various casing strings and the cement sheaths that seal the annular spaces. Figure 16.9 illustrates a number of potential defects in these barriers that could result in a loss of well integrity, potentially leading to CO2 leakage out of a storage complex. Leak paths are shown in Figure 16.9: (a) through the cement, (b) through the casing, (c) through cement fractures, (d) between casing interior and cement, (e) between casing exterior and cement, and (f) between formation and cement. These defects fall into a number of categories with potential causes as summarized in Table 16.7. Cement defects affecting the external casing sheath can equally well affect internal casing plugs, as indicated in the figure.

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Figure 16.9 Cement barrier defects potentially leading to CO2 leakage. Source: After Gasda et al. (2004).

Table 16.7 Summary of barrier defects potentially leading to CO2 leakage Flow path

Defect type or location

Potential root causes of the defect

Annular or microannular flow paths

Debonding between cement and casing

Pressure or temperature cycling during or after cement setting; shrinkage of cement on setting Poor hole cleaning (partial or non-removal of mud and filter cake); shrinkage of cement on setting Poor hole cleaning (partial or non-removal of mud and filter cake) Shrinkage of cement on setting; temperature and pressure changes during well operations Carbonic acid corrosion of the casing or liner

Flow paths within the cement sheath

Debonding between cement and formation Channels Fractures

Flow paths through the casing or liner

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16.2.1 Impact of CO2 on cement The interaction between CO2 and cement has been investigated mostly for the case of brine saturated with CO2 and the discussion below refers to those conditions. Interactions have also been observed and studied between cement and dry scCO2 or scCO2 saturated with water (see Gaus, 2010). When regular Portland cement is exposed to brine saturated with dissolved CO2, a carbonation process of as a result of CO2 hydration (as discussed in Chapter 10): CO2 1 H2 O ! H2 CO3

(16.1)

the leaching of the metallic cation by the acidic solution: CaðOHÞ2 ! Ca21 1 2OH2

(16.2)

and the precipitation of the carbonate: 2 Ca21 1 HCO2 3 1 OH ! CaCO3 1 H2 O

(16.3)

The availability of calcium hydroxide sustains a high pH (B12), allowing precipitation of CaCO3. This deposition cause a reduction in porosity, since the molar volume of calcium carbonate is roughly 20% higher than the hydroxide, which can lead to a healing of any fractures in the carbonated cement. Continued exposure to CO2 will eventually result in the depletion of Ca(OH)2, a decrease in pH, and the dissolution of CaCO3: H1 1 CaCO3 ! Ca21 1 HCO2 3

(16.4)

Finally, if all CaCO3 is consumed, the pH will drop to that of the CO2-saturated brine (B3) and the calcium silicate cement matrix will be converted to silica gel: 3H2 CO3 1 Ca3 Si2 O7  4H2 O 5 3CaCO3 1 2SiO2  H2 O 1 3H2 O

(16.5)

The resulting material would be weak and highly porous, and no longer able to either support the casing or provide a barrier against unwanted flow. Reactions (16.2)
(16.5) define zones of progressive cement alteration, illustrated in Figure 16.10, that have been identified in experimental investigations. Although very long-term CO2 exposure can ultimately result in a loss of cement integrity, field trials and experimental investigations under downhole representative conditions indicate a very slow penetration rate for the carbonation process. Curve fitting of experimental results indicated a square root time dependence of carbonation penetration (in line with Fick’s second law of diffusion), reaching 1022 m after 103 years and 1021 m after 105 years, with carbonation rates decreasing with

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Figure 16.10 Zones of progressive cement alteration under extended aqueous CO2 exposure. Source: After Kutchko et al. (2007).

increased formation brine salinity (see Kutchko et al., 2007). Given these low rates of carbonation for standard oil field cements, the risk that chemical degradation of properly designed, well placed, and undamaged cement would lead to leakage is considered low. The main risk posed by CO2 contact leading to chemical degradation will occur in the situations depicted in Figure 16.8 and described in Table 16.5, where defects in the cement sheath provide flow paths for CO2-saturated brine. In this situation, dissolution of Ca(OH)2, followed by precipitation and then dissolution of CaCO3 can potentially occur at a higher rate because flow through a fracture or microannulus could continuously replenish the acidic brine. As noted above, self-healing may occur in some instances, although experimental investigations demonstrate a fine line between self-healing and further fracture opening, determined by fracture geometry, solution leakage rate, and residence time. A number of proprietary cements have been developed by oil field service companies (e.g., ThermaLockt and EverCRETEt) which lab tests show to be highly resistant to CO2. Although the degradation rate of standard cements has been shown to be very low, the risk posed by leakage arising from cement placement defects (Figure 16.8) can be substantially reduced by the use of these products in critical areas of new well construction, notably over the storage complex, and across any secondary sealing formations and any formations containing or in hydraulic contact with USDW resources. In the initial stage of well abandonment in the Ketzin

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injection pilot, EverCRETEt was used for the cement plug installed in 2013 opposite the perforated interval. The plug was subsequently cored to evaluate the cement plug condition during the final abandonment of the well in 2015.

16.2.2 Impact of CO2 on casing and tubing In an acidic environment, such as that resulting from the dissolution of CO2 in water (Reaction 16.1), steel materials used in well construction will corrode as a result of the reaction: Fe 1 2H1 ! Fe21 1 H2

(16.6)

In the presence of cement, iron in solution can lead to the precipitation of iron carbonate (FeCO3) which can also result in a degree of self-healing of channels or microannuli in the cement sheath. CO2 corrosion is well known in the oil industry (not just in CO2 EOR operations), since CO2 is a not uncommon component in many oil and gas reservoir fluids. This type of corrosion initially appears as localized surface pitting, leading to thinning and eventual perforation of the corroded material, and becomes more severe as CO2 partial pressure, temperature, and flow rate increase. A CO2 partial pressure in excess of 0.2 MPa results in highly corrosive conditions, and specialized corrosion-resistant materials are required. Carbon steel components, such as tubing strings, can also be protected by internally coating with GRE while, at lower partial pressures, carbon steel can also be protected using corrosion inhibitors. However, since CO2 corrosion only occurs in the presence of water, corrosion protection would not be required for those components that are only exposed to dry scCO2. Experience gained from CO2 production wells (see, e.g., Crow et al., 2010) demonstrates that current well construction techniques are able to deliver wells that can maintain long-term integrity in a CO2-rich environment.

16.2.3 Impact of CO2 stream impurities on well integrity Many of the impurities expected to be present in captured CO2, such as SO2, NO2, and H2S, will increase the corrosive potential of the injection stream when in the presence of water. While injection wells may initially be protected under dry conditions, monitoring wells or other wells exposed to the plume will be at risk of increased corrosion. However, the long-term effects of corrosive CO2 stream impurities on well materials are a gap in current knowledge. For injection wells, injection of a chase volume of non-corrosive gas such as nitrogen at the cessation of geological storage operations could be considered. Rehydration of the near-wellbore formation dry-out zone with corrosion-inhibiting fluids would also provide a degree of protection against the adverse effects from re-imbibition of corrosive components in the formation brine.

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16.2.4 Impact of geology on well integrity As well as the processes discussed in the previous sections which can adversely affect well integrity, the geology of the overburden can in some instances have a positive impact on well integrity. Geological formations such as mudstone and salt layers, which exhibit slow deformation under stress (creep), can potentially seal uncemented hole sections and exert a radial stress on the cement sheath that may seal off a leak path through a microannulus (see Loizzo et al., 2017). The identification and characterization of potential geological barriers is therefore an important aspect of storage site assessment and may have a significant impact on the assessment of leakage risk in legacy wells.

16.3

Well remediation

Intervention and remediation may be necessary in the event that well-related leakage of CO2 is detected. If an evaluation of the rate and consequences of leakage indicates that remediation is required, the available options will depend on the type of well affected.

16.3.1 Abandoned wells Leakage through wells that have already been abandoned would typically require: G

G

G

G

Reentry of the well Drilling out of cement plugs and milling of any mechanical (bridge) plugs Possible evaluation of leakage location (e.g., cement bond and ultrasonic image logging, temperature and/or acoustic logging) Re-abandonment using optimal techniques and procedures (e.g., pancake cement plugs, use of CO2-resistant cement)

16.3.2 Injection and monitoring wells An evaluation of the leakage location will be the first step in planning remediation for an injection or monitoring well, and possible evaluation techniques include temperature, acoustic, or cement bond logging. If the well is still required for injection or monitoring service, possible remediation options, following removal of the completion, include: G

G

G

Squeeze of cement or other sealing treatment (e.g., nanoparticle-reinforced epoxy) at the leak point or across a leakage zone, possibly through casing perforations Casing milling, under-reaming, installation, and cementation of a liner or casing patch to remediate leakage along a poor cement sheath Installation of a liner or casing patch to remediate casing corrosion

If the well has reached the end of its service life, or if abandonment and re-drilling is required, the results of the leakage evaluation can be used to make any

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necessary adjustments to the standard abandonment procedure to address the specific conditions of the well.

16.3.3 Cement remediation by biomineralization The precipitation of calcite by ureolytic bacteria, discussed in Chapter 14, has been shown in laboratory and field experiments to be a potential technique to remediate subsurface CO2 leak paths in cement, caprock, or elsewhere (see Cunningham, 2014). A field trial in a hydraulically fracture sandstone formation showed fracture permeability reduction following batch injections of calcium/urea solutions and cultures of the ureolytic bacteria Sporosarcina pasteurii, confirming initial results obtained in bench-scale experiments.

16.3.4 Implications for site selection and monitoring Full assessment of the condition of pre-existing wells at a potential storage site is essential to avoid either excessive remediation expenditure, if competent wells are unnecessarily worked over, or leakage and emergency remediation if wells that do not have competent seals are overlooked. The quality and completeness of data on pre-existing wells, particularly regarding well status (such as the depth of the top of cement for each casing string, the length and location of abandonment cement plugs, etc.) and procedures followed for well abandonment, must therefore be given careful consideration in site screening; the lack of adequate information could be sufficient reason to exclude a potential site if the number of pre-existing wells — and therefore the unquantifiable risk — is significant.

16.4

References and resources

16.4.1 References Baldissera, A.F., et al., 2017. Epoxy-modified Portland cement: effect of the resin hardener on the chemical degradation by carbon dioxide. Energy Procedia. 114, 5256
5265. Cao, P., Karpyn, Z.T., Li, L., 2015. Self-healing of cement fractures under dynamic flow of CO2-rich brine. Water Resour. Res. 51, 4684
4701. Crow, W., Carey, J.W., Gasda, S., Williams, D.B., Celia, M., 2010. Wellbore integrity analysis of a natural CO2 producer. Int. J. Greenhouse Gas Control. 4, 186
197. Cunningham, A.B., et al., 2014. Wellbore leakage mitigation using engineered biomineralization. Energy Procedia. 63, 4612
4619. Freifeld, B., 2009. The U-tube: a new paradigm for borehole fluid sampling. Sci. Drill. 8, 41
45. Gasda, S.E., Bachu, S., Celia, M.A., 2004. Spatial characterization of the location of potentially leaky wells penetrating a deep saline aquifer in a mature sedimentary basin. Environ. Geol. 46, 702
720. Gaus, I., 2010. Role and impact of CO2
rock interactions during CO2 storage in sedimentary rocks. Int. J. Greenhouse Gas Control. 4, 73
89.

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Le Guen, Y., et al., 2008. CO2 Storage—Managing the Risk Associated with Well Leakage over Long Timescales. Society of Petroleum Engineers (SPE 116424). 2008 SPE Asia Pacific Oil & Gas Conference and Exhibition, Perth, Australia. Kutchko, B.G., Strazisar, B.R., Dzombak, D.A., Lowry, G.V., Thaulow, N., 2007. Degradation of well cement by CO2 under geologic sequestration conditions. Environ. Sci. Technol. 41, 4787
4792. Loizzo, M., Lecampion, B., Mogilevskaya, S., 2017. The role of geological barriers in achieving robust well integrity. Energy Procedia. 114, 5193
5205. Mosleh, M.H., Durucan, S., Syed, A., Shi, J.-Q., Korre, A., Nash, G., 2017. Development and characterisation of a smart cement for CO2 leakage remediation at wellbores. Energy Procedia. 114, 4147
4153. Nakajima, T., Xue, Z., Watanabe, J., Ito, Y., Sakashita, S., 2013. Assessment of well integrity at Nagaoka CO2 injection site using ultrasonic logging and cement bond log data. Energy Procedia. 37, 5746
5753. Parker, M.E., Meyer, J.P., Meadows, S.R., 2009. Carbon dioxide enhanced oil recovery— injection operations technologies. Energy Procedia. 1, 3141
3148. Prevedel, B., Martens, S., Norden, B., Henninges, J., Freifeld, B.M., 2014. Drilling and abandonment preparation of CO2 storage wells—experience from the Ketzin pilot site. Energy Procedia. 63, 6067
6078. US EPA (US Environmental Protection Agency), 2010. Federal requirements under the Underground Injection Control (UIC) Program for carbon dioxide (CO2) geologic sequestration (GS) wells; final rule. Federal Register. 75, 77230.

16.4.2 Resources CO2CRC Otway research facility: www.co2crc.com.au/otway-research-facility. DNV Report No.: 2011
0448, 2011. CO2Wells: guideline for the risk management of existing wells at CO2 geological storage sites. Available at www.globalccsinstitute.com/ publications/guideline-risk-management-existing-wells-co2-geological-storage-sites. IEAGHG International Research Network on Wellbore Integrity: www.ieaghg.org/networks/ wellbore-integrity-network. Ketzin project: www.co2ketzin.de/nc/en/home.html. MiReCOL (EU project developing a handbook and web tool for remediation and corrective action at geological storage sites): www.mirecol-co2.eu. ULTimateCO2 project: www.ultimateco2.eu.

Saline aquifer geological storage

17

Chapters 11 to 16 introduced and discussed the wide range of features, events, and processes that bear upon the design and operation of a geological storage (GS) project. The current chapter builds on this foundation in describing the key elements and phases in a saline aquifer storage project, starting from site screening, assessment, and selection, through storage development planning to storage operations and monitoring. A number of case studies are discussed and the chapter concludes with a review of the current R&D focus areas in saline aquifer storage. Project maturation and execution activities discussed here are assumed to follow a generic stage-gate project management process of the type illustrated in Figure 17.1 (see Cooper, 2008), where AR1 to AR6 indicate assessment reviews preceding decision gates G1 to G6. Each project stage typically follows a common structure, shown in Figure 17.2, starting with the mandate received from the decision maker or decision body at the successful conclusion of the previous stage—essentially the what, when, and how (i.e., resources) of the projects team’s work in the current stage—and proceeding through analysis, review, and reporting to the next decision gate. A number of references and resources describing this project management approach are listed at the end of the chapter.

17.1

Storage site screening, assessment, and selection

17.1.1 Storage site identification and screening The main objective of the initial, feasibility stage in a geological storage project will be to demonstrate within an acceptable range of uncertainty that, following further assessment, a storage site can be found that will be suitable for the project requirements. Typical work process steps for site screening are illustrated in Figure 17.3 and briefly discussed below.

Obtain data and identify prospective sites The screening process described here assumes that the regional location of the project is given, and that basin and regional screening studies have confirmed the presence of a potentially suitable saline aquifer in the region. The reviews of UK and Norwegian North Sea storage potential and the US NETL Carbon Storage

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00017-9 © 2017 Elsevier Inc. All rights reserved.

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Feasibility

Selection

G1

AR1

Definition

G2

AR2

Execution

G3

AR3

Operation

G4

AR4

G5

AR5

Postclosure

Closure

G6

AR6

PCR

Figure 17.1 Generic stage-gate project management process for a geological storage project.

Project Stage Mandate Decision statement, decision criteria, allocation of resources and timeline to next gate.

Decision Gate

Activities Information gathering and analysis activities to support the mandated decision at the next gate.

Deliverables Specified deliverables, plans, reports, etc. required to support the decision and enable progress to next stage.

Assurance Review Functional assurance of deliverable quality and completeness

Figure 17.2 Generic structure of a project stage.

Obtain data and identify prospective sites

Analyze data and perform technical screening

Assess uncertainty on key performance measures

Identify and rank risks and generate initial risk register

Conduct first contact meetings with regulators

Execute screening stage public outreach activities

Rank and shortlist sites for assessment and selection

Specify selection criteria to be used in next stage

Define the workplan for site assessment and selection

Prepare Exploration permit application for site assessment if required

Secure endorsement for budget, resources, workplan, and decision basis (selection criteria) for the assess stage

Figure 17.3 Site screening stage process steps.

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Program offshore CCS assessment are examples of such regional studies (see Resources), the output from which can provide a starting point for site screening, assessment, and selection. As well as regional and site-specific data, the growing knowledge base of published results from pilot and demonstration projects provides an important source of information for all stages of project planning and operations. The CO2 Storage Data Consortium (CSDC) has been established to promote the sharing of data and knowledge from CO2 storage projects (see Ringrose et al., 2017 and CSDC in Resources).

Analyze data and perform site screening Screening criteria used in the initial screening of potential sites will have been established and agreed with the decision body at project initiation and will typically cover all the essential requirements that must be met by a site to justify further assessment, as well as a set of additional aspects that will help to determine the relative attractiveness (ranking) of sites that meet the minimum requirements. Table 17.1 shows a non-exhaustive example of a set of screening criteria grouped into essential and non-essential but desirable factors, while Figure 17.4 illustrates the set of screening criteria (there called qualifying criteria) used in the FutureGen project (see FutureGen, 2007). Other examples of screening checklists and methodologies can be found in the references at the end of the chapter. The level of detail in site screening analysis will have to be tailored to the available data, with greater emphasis on data gathering in the site assessment stage in areas where legacy data is lacking. In hydrocarbon provinces, formation specific data may be readily available from regulatory or public domain sources, while in other cases data may be very limited and available only on a regional scale. Several case studies (see CO2STORE, 2008) have noted the difficulty in bringing prospective sites that lack data from previous hydrocarbon exploration activity to the level of confidence required to justify project investments. Screening criteria relating to regulatory issues are best addressed through first contact meetings with the relevant regulatory authorities. Early engagement will provide insight into regulatory perspectives that will help the project team focus their efforts and avoid time and money being wasted on sites that may be no-go from the regulator’s perspective. Criteria relating to public acceptance and community issues will need to be addressed within the context of an overall outreach plan, which should be developed at this stage. Best practice guidance is available in NETL (2010).

Screening stage uncertainty assessment Although available data may be sparse at the screening stage, an early assessment of the range of uncertainty in the main parameters affecting capacity and containment will aid in the ranking of shortlisted sites. For example, a simple assessment of capacity uncertainty would be appropriate for site screening. Input parameter

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Table 17.1 Example of storage site screening criteria Geological storage aspect

Criterion

Remarks

Essential criteria Capacity

Connected net pore volume (Storage formation area 3 gross thickness 3 net/gross ratio 3 porosity) Target formation depth between 800 and 2500 m

Containment

Injectivity

Accessibility

Thickness and capillary entry pressure of the primary seal (cap rock), and lateral continuity over the expected areal plume extent Tectonic stability and lack of faults or fractures that are likely to result in leak paths through the primary seal Engineered potential leak paths (pre-existing wells) are absent or adequately characterized to assess leakage risk Permeability 3 net thickness of the storage formation Proximity of the site to the prospective customers (CO2 suppliers) of the project

Lack of regulatory or other impediments preventing required surface and subsurface access

A minimum connected pore volume will be required to ensure that the project’s target injection volume can be injected without excessive pore pressure increase Target depth . 800 m to achieve dense phase storage and efficient use of available pore space; , 2000 to 2500 m to ensure adequate porosity and permeability and to minimize well costs Integrity of the primary seal to ensure containment of the target injection volume Presence of faults and/or fractures does not preclude site suitability, but will require additional characterization and monitoring Presence of wells does not preclude site suitability, provided their condition is known or can be assessed without undue costs Ensures adequate injectivity to achieve the desired storage rate with a reasonable well count For a utility geological storage project proximity to customers and future growth potential within the facility catchment area will be an essential commercial consideration Regulators may specify formations that may be used for geological storage; presence of other natural subsurface resources (hydrocarbons, geothermal energy, or potable water), protected and sensitive surface areas or population centers may preclude use of a formation or site for geological storage (Continued)

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Table 17.1 (Continued) Geological storage aspect

Criterion

Remarks

Maturability

No factors are identified that would prevent assessment of the site to the required level of confidence within the planned timeframe of the assess and select phase

Factors that might impact on the assess phase work include ongoing regulatory consultation, moratorium on drilling or other essential data gathering, ongoing geological storage or other major industrial projects, ongoing or recent site-specific issues that would impact on public acceptance

Desirable criteria Capacity

Reservoir heterogeneity; low vertical permeability due to intra-reservoir low permeability layers

Reservoir heterogeneity; risk of lateral sealing leading to compartmentalization

Containment

Presence of secondary seals

Presence of nearby analogue reservoirs demonstrating containment Characterization Availability of characterization data, for example, from previous hydrocarbon exploration

Lack of impediments to cost-effective monitoring Absence of other interests in the prospective site

Small- and intermediate-scale reservoir heterogeneity can maximize the pore volume invaded by CO2, increase residual trapping, and encourage CO2 dissolution Reservoir compartmentalization will lead to elevated injection pressures and risk of leakage through fracture initiation or reactivation Additional impermeable layers above the primary seal may prevent further migration of leaking CO2 into the vadose zone Nearby gas or natural CO2 accumulations or reservoirs used for natural gas storage increase confidence in containment Existing data reduce the uncertainty on screening stage estimates and will reduce the cost of data gathering in the assessment stage, although the containment risk posed by existing boreholes will be a primary concern Surface constraints may adversely affect the cost of essential monitoring, such as 4D seismic Areas that are protected for military use, for natural or landscape (Continued)

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Table 17.1 (Continued) Geological storage aspect

Criterion

amenity, covered by existing industrial usage or rights, or subject to other special interest groups

Accessibility and social context Assessment of local community perspectives and sensitivities on environmental issues

Risk management

Relative risk profile across the full range of risk factors

Presence of vulnerable zones that could be impacted by the project

Availability of risk mitigation options

Conditions affecting cost-effective monitoring

Economics

Remarks

Indicative range of life cycle storage cost (PV$/t-CO2)

Sources such as the local press, web sites of environmental groups and initial dialogue with communities can give an indication of potential sensitivities Potential risk factors considered should include technical, commercial, economic and financial, public and political (both acceptance and liability) The presence of shallow potable aquifers or similar vulnerable zones may impose excessive monitoring and mitigation costs or liabilities on the project Mitigation strategies can be outlined, although not yet defined in detail, for all potential highrisk factors The absence of factors that would preclude cost-effective monitoring, such as impediments to 4D seismic, or the presence of favorable conditions that would provide early warming of unexpected plume migration An early indication of the possible range of storage costs (Low, Mid, and High cases), discounted at the appropriate corporate discount rate

minimum and maximum values can be estimated and a Monte Carlo simulation performed to determine low, middle, and high capacity estimates, typically corresponding to 90%, 50%, and 10% probabilities of being exceeded, respectively. A further objective of uncertainty analysis at the site screening stage is to identify those uncertainties that can be addressed by additional data gathering and studies during site assessment and selection. For those uncertainties that have a high potential impact on project performance, the acquisition of data that significantly

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Site characteristics Surface characteristics

Subsurface characteristics

US location

Mineral rights

Monitoring access

Water rights

435

Geological characteristics Formation properties

Storage capacity

Proximity to sensitive areas

Deep saline formation

50 Mt total capacity

Adequate depth for scCO2

1 Mt/year injection rate

At least 15 km from public access, marine shoreline, lakes, and other sensitive features

Drinking water

Storage complex does not contain actual or potential drinking water resources

Safety

No known transmissive faults

Permitting

Deep well injection permit feasible

Adequate reservoir seal

Figure 17.4 Site screening criteria used in the FutureGen project. Source: After FutureGen (2007).

reduces uncertainty will have a high value of information to justify acquisition costs.

Screening stage risk assessment The identification and assessment of risks that could impact on desired project performance, and the subsequent identification and assessment of safeguards—both natural and engineered—that contribute to the prevention of unwanted events and mitigation measures that limit the impact if such events do nevertheless occur, are activities that take place within the overall risk management framework for a project. Figure 17.5 shows schematically how such a framework underpins risk management activities through the project life cycle. The preparation of a risk register, capturing both site-specific and more generic risks, is an important early step in the risk management process and an example of a generic risk register for a geological storage project is shown in Table 17.2. The focus of risk analysis as an input to site screening and ranking is to identify any risks associated with each candidate site that have the potential for significant economic and HSE impact or could, in the extreme, become show-stoppers. The degree to which risks can be quantified at the screening stage is likely to be limited, with the exception of sites that have comprehensive existing datasets such as depleted hydrocarbon fields, so the risk assessment input to ranking and screening may be largely qualitative. Similar to uncertainty analysis, a further objective of

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Evaluate storage feasibility

Establish monitoring requirements

Evaluate monitoring performance

Select storage site

Select monitoring technologies

Assess site-specific storage risks

Establish performance targets

Adapt monitoring plans

Characterize geological safeguards

Identify contingency monitoring

Evaluate storage performance

Select engineered safeguards

Identify control measures

Evaluate these initial safeguards

Evaluate these additional safeguards

Storage risks suitable?

Storage risks acceptable?

Monitoring performance acceptable? yes yes (final) no

continue

yes

Storage performance acceptable? yes (final) no Implement control measures continue

no

yes Site characterization

no

Site closure yes

MMV planning

Performance review and site closure

Figure 17.5 Schematic geological storage project risk management framework. Source: After Shell Canada Quest Project MMV Plan (2012).

risk assessment at the screening stage is to identify risks that need to be addressed by additional data gathering and studies during site assessment.

Ranking and shortlisting of potential sites The expected performance of each potential storage site against the agreed screening criteria and an early assessment of the risks and uncertainties pertaining to each site provide the basis for site ranking. All sites that meet the essential requirements could be considered for further assessment, or the secondary criteria can be used to reduce the number of candidate sites taken forward for further assessment. Various approaches can be taken to combining performance against the diverse range of screening criteria to come up with a single ranking score; simple weighting factors, Monte Carlo simulation and the use of fuzzy logic being some of the techniques that have been reported. A costly lesson from the oil and gas industry is that increasingly complex evaluation methods do not always lead to increasingly sound decisions. In general, simplicity will enhance transparency in the final proposal and will contribute to decision quality.

Table 17.2 Generic early-stage risk register for a geological storage project Category Risk statement

Cause(s)

Indication

Possible risk mitigation measures

Seal absent, permeable or Leakage of CO2 through the geochemically altered by primary seal as a consequence CO2 over part of the plume of geological heterogeneity

Geophysical monitoring indicates CO2 above seal

Leakage of CO2 through the primary seal as a result of geomechanical failure

Primary seal fractured as a result of excess pore pressure from injection

Fault seals

Leakage of CO2 through the primary seal as a result of permeable paths along faults

Permeable fault planes intersect the CO2 plume

Well seals

Leakage of CO2 through the primary seal as a result of permeable paths along wells

Poor well construction or degradation of cement sheaths

Pressure drop or rate increase in injection well indicates fracturing Geophysical monitoring indicates CO2 above seal associated with faulting Geophysical monitoring indicates CO2 above seal associated with wells

Adequate site characterization; site selection to require presence of effective secondary seals. Revise injection plan (relocate well(s), reduce rate, etc.) Reduce injection rate to ensure pore pressure is below seal fracture pressure; revise injection plan (relocate well(s)) Adequate site characterization; site selection to avoid faults in the plume area. Revise injection plan (relocate well(s), reduce rate, etc.) Adequate site characterization, ensuring complete inventory of existing wells. Well remediation

Technical: containment Primary seal

Technical: capacity Pore space inadequate to store planned CO2 volume due to low porosity

Connected pore volume lower than expected due to low formation porosity

Increasing pore pressure indicating low connected pore volume

Revise injection plan (relocate wells over a wider area); pump off water to reduce pore pressure and dispose elsewhere; reduce planned storage volume (Continued)

Table 17.2 (Continued) Category Risk statement

Cause(s)

Indication

Possible risk mitigation measures

Connected pore volume low due to compartmentalization by faults or unexpected sedimentary geometry

Increasing pore pressure indicating low connected pore volume

Revise injection plan (relocate wells outside the compartment); pump off water to reduce pore pressure and dispose elsewhere; reduce planned storage volume

Unexpected movement of the CO2 plume as a consequence of geological heterogeneity

Unexpected sedimentary or structural geometry, undetected fracture system, or high permeability layers

Geophysical monitoring shows unexpected plume movement

Unexpected movement of the CO2 plume due to hydrodynamic regime

Unexpected hydrodynamic gradients

Geophysical monitoring shows unexpected plume movement

Reassess future plume movement and implications for containment (seals, faults, wells); revise injection plan if necessary (relocate well(s), reduce rate, etc.) Revise injection plan (relocate well(s), etc.). Modify hydrodynamic gradients using water production wells

Connected pore space inadequate to store planned CO2 volume due to compartmentalization

Technical: footprint

Technical: injectivity Required injection rate cannot be achieved due to low formation permeability

Lower than expected Planned injection rate not Adequate site testing including permeability, possibly due to achieved at the design injection test; recompletion of geological heterogeneity injection pressure existing or re-design of future injection wells (e.g., longer perforated interval, deviated or horizontal wells). Relocate injection wells

Required injection rate cannot be achieved due to formation damage

Loss of permeability due to damage by drilling and completion fluids or geochemical reaction with CO2

Redesign drilling and completion fluids Formation damage for future wells. Stimulate damaged indicated by increasing well(s) using acid or fracture injection pressure and/ treatments or pressure fall-off surveys

Economic Well construction cost increases High oil prices and tight market conditions for well due to high oil price driving drilling and completion up demand for drilling rigs services and well construction services

Oil market volatility; geopolitical situation

Lock-in service contracts; hedge against adverse oil price movement

Commercial CO2 sources do not mature as anticipated

Changes in regulatory of economic drivers for CCS

Cost of CO2 emissions permits Lack of demand for emissions permits due to economic falls below the storage cost of conditions; changes in the project energy mix (gas, nuclear, renewable)

Slow progress or delays Progress the storage utility project in line with the maturing CO2 source in planned source projects projects Emissions permit market Hedging by trading emissions options trends and futures

Organizational Limited number of experienced Increasing frequency of Develop Human Resources policies to Project team cannot be attract and retain the required new geological storage engineers being sought by adequately resourced due to a competencies project announcements many concurrent storage lack of geoscientists with projects relevant experience (Continued)

Table 17.2 (Continued) Category Risk statement

Cause(s)

Indication

Possible risk mitigation measures

Political: regulatory and permitting Rapid progress on Other projects targeting the Rights to the required pore competing project(s) same storage formation space cannot be secured due reach maturity earlier than to competing projects of other expected operators History of active public Strong public opposition halts Inadequacy of the public opposition in the the permitting process outreach program. Equivocal region of potential national or state policy with sites respect to CCS

Project closure permitting is delayed due to regulator’s lack of confidence in long-term model predictions

Inadequate monitoring plan; poor monitoring data or match to model

Lack of maturity of the Regulatory changes impose regulatory framework at unexpected and/or project initiation unachievable requirements on the project

Maintain an overview of existing and potential alternative uses of the site or sites under assessment, starting at the screening stage Comprehensive public outreach program, starting at the site screening stage with initial communication to open a dialogue with communities at potential storage sites Uncertainty in long-term Include long-term model predictive capability as an objective in performance developing the monitoring plan; prediction does not ensure regulatory approval and narrow through the compliance with the plan operating phase Ongoing definition of the Lobbying to influence the regulatory process; delay of the project until the regulatory at project regulatory framework is sufficiently initiation mature

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Defining storage site selection criteria In contrast to the site screening criteria which can be largely internally defined by the project organization, a comprehensive and effective set of site selection criteria needs to include input and requirements from a broader range of stakeholders. Requirements internal to the project organization will cover a range of issues including: G

G

G

Technical (capacity, injectivity, containment) Economic (project capital and operating costs, life cycle unit storage cost vs expected emissions trading market price) Commercial (maturity and future growth potential of the CO2 supply base, commercial access to the existing or emerging CO2 transport infrastructure)

Table 17.3 shows an example of a technical selection criteria published by the Alberta Research Council and applied by Shell Canada in the Quest CCS project (see Section 17.4). In addition, regulatory requirements for eventual storage permitting, monitoring, and project performance also need to be included in the selection criteria, since there is little point in selecting a site for which the regulatory requirements are prohibitively expensive or impossible to meet. Best practice in public outreach also suggests that incorporation of communitydefined measures in the selection criteria will build trust and confidence and help to ensure eventual acceptance of the selected site (see, e.g., Brunsting et al., 2011).

Defining the workplan for storage site assessment and selection The workplan for the site assessment and selection stage describes the scope and level of detail of work to be carried out on each shortlisted site, as well as an estimate of the resourcing, budget and schedule implications of these activities. In addition to updates to the risk and uncertainty assessment, which occur at each stage, the main elements of this workplan are summarized in Table 17.4. As well as addressing site selection requirements, data acquisition may also be planned to test the effectiveness of critical monitoring techniques. For example, if seismic data quality is known to be variable at some potential sites it may be desirable to acquire test lines focused on the storage complex to ensure seismic quality will be adequate for plume monitoring. This was a specific consideration in siting CO2 injection wells on Barrow Island, Australia as part of the Gorgon project, where some potential areas were excluded due to poor seismic data quality (see Chevron, 2005).

17.1.2 Storage site assessment and selection The objective of the site assessment and selection stage is to provide the basis for selecting a storage site and an associated engineering concept to go forward into the planning and design stage of the project. This will be the candidate site

Table 17.3 Technical site selection criteria applied in Shell Canada’s Quest CCS project Criterion No. Criterion level

Unfavorable

Preferred or favorable

Critical

Intermediate and excellent; many pairs (multi-layered system)

Essential

1

Reservoir-seal pairs; extensive and competent barrier to vertical flow

Poor, discontinuous, faulted, and/or breached

2

Pressure regime

3 4

Overpressured, pressure gradients . 14 kPa/m Absent Yes

Monitoring potential Affecting protected groundwater quality Seismicity High #Moderate Faulting and Extensive Limited to moderate fracturing intensity Intermediate- and regionalHydrogeology Short flow systems, or scale flow compaction flow, saline aquifers in communication with protected groundwater aquifers

5 6 7

Desirable

8 9 10

Depth Located within fold belts Adverse diagenesis

Quest storage complex (Basal Cambrian Sands)

Three major seals (Middle Cambrian Shale (MCS), Lower Lotsberg and Upper Lotsberg Salts) continuous over entire CO2 storage area of interest (AOI). Salt aquicludes thicken updip to NE Pressure gradients , 12 kPa/ Normally pressured , 12 kPa/m m Present Present No No

Low Limited. No faults penetrating major seal observed on 2D or 3D seismic Intermediate- and regional-scale flowsaline aquifer not in communication with groundwater

,750 800 m Yes

.800 m No

.2000 m No

Significant

Low

Low

Temperature Pressure Thickness Porosity Permeability Caprock thickness

Gradients $ 35 C/km and low surface temperature ,35 C ,7.5 MPa ,20 m ,10% ,20 mD ,10 m

Gradients , 35 C/km and low surface temperature $ 35 C $ 7.5 MPa $ 20 m $ 10% $ 20 mD $ 10 m

Well density

High

Low to moderate

11

Geothermal regime

12 13 14 15 16 17

18

Source: From Shell Canada Quest Storage Development Plan.

Gradients , 35 C/km and low surface temperature 60 C 20.45 MPa .35 m 16% Average over AOI 20 500 mD Three caprocks: MCS 21 75 m, Lower Lotsberg Salt 9 41 m, Upper Lotsberg Salt 53 94 m Low

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Table 17.4 Major elements of the site assessment and selection workplan Element

Description

Data acquisition plan for site selection

Defines, with reference to the proposed site selection criteria and for each shortlisted site, what additional data is needed in order to achieve the level of confidence required for site selection Describes the specific analysis and modeling activities, including uncertainty analysis, to achieve a quality decision basis for site selection Based on the site-specific risk assessment and uncertainty analysis and regulatory requirements, this will define an initial monitoring plan that will be refined during the detailed design stage Activities to ensure understanding and alignment with the regulatory requirements at the end of the assess and select stage Defines, in line with the overall public outreach strategy of the project, the specific public engagement activities during the select stage An update of the overall project plan, including costs, schedule, economics, resourcing, contracting plan, and budget requirements for the next stage

Analysis and modeling plan for site selection Preparation of the initial monitoring plan

Regulatory communication plan Public outreach plan

Update project plan

from the short list that, given the current range of uncertainty, is judged most likely to be able to deliver the specified project requirements, both technical and non-technical. The accompanying engineering concept will specify the surface facility requirements, number and preliminary locations of injection wells and any observation wells proposed as part of the monitoring plan, as well as the low mid high range for the injection profile over the full operating lifetime of the project. This will form the basis of the Storage Development Plan (SDP), discussed below. While the primary customer of the deliverables from the site screening stage was the internal decision maker, the outputs from the site assessment and selection stage also need to meet the permitting requirements of the relevant regulatory bodies. Detailed regulatory requirements for each shortlisted site will have been clarified during the screening stage to ensure they are adequately addressed by the assessment and selection stage workplan. The main work process steps for this stage are briefly discussed below.

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Table 17.5 Components of storage performance prediction during site assessment Prediction element

Description

Areal and vertical The CO2 distribution (dissolved, trapped, mobile) in the storage extent of the CO2 formation, caprock and any plume versus time invaded overburden formations

Pressure behavior versus time

Prediction of both near-well and far-field pressure behavior

Injectivity performance versus time

Sustainable well injection rate

Estimate of leak probability and rate for specific modeled leak paths (faults, existing wells, etc.) Effectiveness of Possibility to test remediation potential remedial options such as injection or measures back-production Leakage probability and rate versus time

Impacts Storage capacity and evolving contribution of trapping mechanisms; areal extent of required containment assurance; necessity of remedial measures in the event of specific leakage risks such as faulted or fractured zones or regions with high legacy well risk Potential pressure limitation on storage capacity. Impact of pressure on well injectivity and well count. Far-field hydrodynamic impact Required well count to achieve target storage rate; possible need for additional wells in later storage life Provides a basis for the risk-based monitoring plan and investigation of mitigation and remediation measures Potential impact on well count, placement or timing; monitoring plan

Execute site assessment analysis and modeling workplan Once the required site-specific data has been acquired, geological and fluid flow modeling will be cornerstone of the subsurface site assessment work. Models will be built using a detailed description of the relevant geological (structural and stratigraphic), fluid-dynamic, and other properties of the storage target and relevant overburden formations. All features and processes, as described in Chapters 12 16, that are relevant to the modeling objectives for this stage should be included in these models. The main objective of the analysis for site selection is to predict the evolution of the plume of injected CO2 at each assessed site and to determine the range of uncertainty in each prediction given the range of uncertainty in the input parameters as well as in the models. The main components of these predictions and their implications are shown in Table 17.5.

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As well as the technical implications noted in the table, many of these factors will also have financial, commercial, regulatory, and public acceptance implications which will require equally careful consideration in the overall assessment.

Site assessment risk and uncertainty analysis The risk and uncertainty analysis conducted as part of the site assessment workplan is perhaps the most important during the project life cycle; getting it right here ensures a firm foundation for the monitoring activities and remediation contingencies that will make the project robust in meeting its targets; getting it wrong increases the exposure to unexpected future events for which the project will be unprepared and which may well prove to be unmanageable. The uncertainty analysis objectives at this stage are twofold: first to understand the possible range of performance of the project (capacity, containment, footprint, injectivity) that is consistent with the current state of knowledge of the relevant FEPs, and second to identify which aspect(s) of the subsurface characterization have the greatest impact on the performance uncertainty (e.g., formation or caprock permeability, geological modeling concept). A range of performance predictions from the modeling tools can be presented either using a set of discrete cases or realizations, for example, Low, Best Estimate, and High cases, or as a continuous probability curve, from which probability levels can be read (e.g., P90, P50, and P10) and cases representative of specific probability levels can be generated. Single factor and multivariate sensitivity analysis and experimental design are techniques commonly used to assess performance prediction uncertainty. Having assessed the range of uncertainty in predicted performance, the next requirement will be to determine the consequence of these uncertainties, whether and how they can be further reduced, and what remediation contingencies would need to be included in the detailed design, execution, and operational stages for each prospective site. This will indicate the degree to which those uncertainties with the potential to materially affect project performance can be managed through the project life, which is an important input to the final ranking and site selection.

Prepare initial monitoring plan An initial monitoring plan for the site proposed to be selected can be prepared when the site assessment stage risk and uncertainty analysis has been concluded and when regulatory requirements have been confirmed through execution of the relevant communication plan. The fundamental objective to be achieved by the monitoring activity is the management of risk and the reduction of uncertainty during the operating stage, to ensure a safe and cost-effective storage operation and, ultimately, straightforward site closure and liability transfer. The guidelines for sub-seabed CO2 disposal

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Risk characterization

… likelihood and severity of impact of stressors (e.g., CO2 leakage) on receptors (e.g., ecosystems, underground water resources, human health)

Impact hypothesis

… a statement of the predicted changes in and around the storage complex as a result of CO2 injection (e.g., degree of pressure build-up, areal movement and extent of injected fluids, extent of infiltration into caprock)

Testable hypotheses

Data to test hypotheses

… elements of the overall impact that are amenable to testing to determine whether changes and consequences are within the predicted range.

… measurements required to test these hypotheses, and determine the level of changes and consequences of any deviations from the predicted impact.

Figure 17.6 Formulation of monitoring objectives. Source: After IMO (International Maritime Organization) (2007).

adopted as part of the London Protocol (see IMO, 2007) describe the formulation of monitoring objectives using the framework shown in Figure 17.6. The impact hypothesis is a concise but sufficiently broad statement of the expected consequences of CO2 injection, and the monitoring plan is derived from this statement by considering the following questions (IMO, 2007): G

G

What testable hypotheses can be derived from the impact hypothesis? What measurements are required to test these hypotheses and determine the levels and consequences of any deviations from the expected outcome?

The Measurement, Monitoring, and Verification (MMV) plan prepared by Shell Canada for the Quest project (see Resources) follows a similar approach illustrated schematically in Figure 17.7. In this case the impact hypothesis is based on the expected efficacy of the existing (i.e., geological) and engineered safeguards in relation to the risks identified in the project risk management plan. The monitoring plan resulting from this type of analysis will identify the type, location, and frequency of specified measurements as well as the measurement-specific performance requirements such as spatial resolution, accuracy, etc., that will be required to meet the monitoring objectives. The plan should also be adaptive, incorporating a review and feedback mechanism, to enable updates throughout the project life in the light of field data, the actual performance and emerging capabilities of monitoring technologies, and so forth. An overview of monitoring technologies is the subject of Chapter 19, while a number of examples of monitoring and verification plans are included in the References and resources section at the end of this chapter.

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Assess site-specific storage risks

Establish definitions for loss of conformance and loss of containment. Identify potential threats and consequences associated with these risk events.

Characterize geological safeguards

Identify and appraise the integrity of each geological seal within and above the storage complex.

Select engineered safeguards

Identify and assess the engineering concept selections that provide safeguards against unexpected loss of well integrity.

Evaluate these initial safeguards

Evaluate the expected efficacy of these initial safeguards in relation to the identified conformance and containment threats, and potential consequences.

Establish monitoring requirements

Define monitoring tasks to verify the performance of these initial safeguards and, if necessary, trigger timely control measures.

Select monitoring plans

Select monitoring technologies for each task (baseline as well as injection and closure phase monitoring) using a cost versus effectiveness ranking.

Establish performance targets

Evaluate the expected monitoring capabilities and establish required performance level to achieve the monitoring tasks

Identify contingency monitoring

Develop contingency plans with clear implementation criteria to replace under performing monitoring system or extend monitoring in the case of deviations

Identify control measures

Design interventions, including operational controls, to reduce the likelihood or the consequence of any unexpected loss of conformance or containment.

Evaluate these additional safeguards

Systematic evaluation of the expected effectiveness of the additional safeguards in reducing storage risks to as low as reasonably practicable.

Figure 17.7 Shell Canada Quest MMV plan design process. Source: After Shell Canada Quest Project MMV Plan (2012).

Defining optimization criteria for storage planning During the storage planning stage a range of optimization decisions may be addressed, such as: G

G

G

G

G

Number and location of injection wells versus storage capacity or versus leakage risk Maximum injection pressure versus storage capacity or versus leakage risk Number and location of monitoring wells versus containment uncertainty or versus leakage risk Risk reduction effectiveness of alternative monitoring techniques versus cost Material selection versus cost and schedule

To avoid the need to have constant recourse to the decision body, it is helpful if the criteria required to make these optimization choices can be defined in advance, endorsed at the decision gate and delegated to the project team. Some examples of optimization criteria that might be applied are shown in Table 17.6.

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Table 17.6 Examples of delegated decision criteria for optimization during detailed design Type of optimization

Generic criterion

Example

Value maximization

Provided an internal rate of return of 15% is achieved, maximize net present value at a 10% discount rate

Risk reduction effectiveness

Provided the expected leak rate is below the specified tolerable threshold, implement leak rate reduction measures if the cost to avoid leakage is below an agreed threshold, which may be related to the cost of emissions

Positive VOI

Implement measures to reduce uncertainty that have a positive Value of Information (VOI), including all costs of acquisition, interpretation, and follow-up actions

Economic Cost vs capacity Cost vs schedule

Risk Cost vs leakage risk

Other Cost vs uncertainty

17.2

Storage development planning

During the project definition stage (see Figure 17.1), the surface and subsurface engineering design will be brought to the level required to support budgetary cost estimates, detailed design, contracting and procurement, and permitting, to enable the final decision to go ahead with project execution. The SDP documents the basis of this engineering design, describing the way in which the storage capacity of the host formation will be utilized to achieve specific project storage requirements. Some examples of SDPs, including those prepared as part of the UK Strategic CCS Storage Appraisal project, are available online (see Resources). Based on detailed simulation models, updated with all data gathered during the earlier project stages, important elements of the SDP include: G

G

G

G

A detailed description of the features of the storage complex relevant to geological storage Optimization of primary injection (well number and location, injection pressure, etc.) Viability of injection strategies to enhance trapping Requirement for and effectiveness of strategies to control pressure buildup

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Storage optimization

Trapping control strategies

Primary injection optimization

Pressure control strategies

• Enhancing residual trapping • Accelerating solubility trapping

• Optimal injection pressure • Number, design, and location of injection wells • Expected injection rate versus time, and uncertainty range • Injection well operating limits (rate and pressure)

• Expected reservoir pressure versus time, and uncertainty range • Preventative and corrective pressure control measures • Number, design, and location of pressure control wells • Expected brine production rate versus time, and uncertainty range

Figure 17.8 Elements of storage optimization. G

G

G

Assessment of the main uncertainties in project performance, and justification for monitoring activities to address those uncertainties Assessment of the main risks and identification of monitoring, mitigation, contingency, and remediation measures A reference case and uncertainty range on plume behavior (footprint, pressure, etc.) that will be the basis of regulatory controls (e.g., invoking remediation in the event of significant deviations)

A number of interlinked optimizations therefore need to be addressed in defining the SDP, as shown schematically in Figure 17.8, and described in the following sections. Sensitivity analysis, taking account of the uncertainty in key input parameters, is applied on the detailed subsurface and surface facility models to evaluate a range of different engineering designs and arrive at a preferred solution. Commonly used methods include single factor and multivariate sensitivity, experimental design and Monte Carlo simulation, while techniques such as linear optimization and machine learning have also been applied (see Govindan et al., 2017). Broadly speaking, the objective of this evaluation will be to identify the engineering design which performs “best” in the face of the current uncertainties. As well as, for example, high capacity with low leakage risk and cost, the desired outcome will generally also preserve options that enable a flexible response as subsurface uncertainties are resolved—for better or worse—during the operational phase.

17.2.1 Primary injection optimization The approach to the optimization of primary injection (in terms of injection pressure, rate, well count, etc.) will strongly depend on whether the storage project is linked to a single CO2 source with a well-defined delivery profile, or has more of the nature of a storage utility, in which case the project operator will want to keep

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open options to conclude additional disposal agreements at future dates, as further insight is gained into the performance and capacity of the storage complex. In this situation, flexibility to accommodate these options will be an important consideration in defining the SDP and in the optimizations discussed in the following sections.

Optimum injection pressure The optimum injection pressure will be influenced by a wide range of geological, geomechanical, and engineering factors, as summarized in Table 17.7. The increased effectiveness of residual trapping at higher pressures is a consequence of smaller pores being invaded by the non-wetting phase (scCO2). This increases both residual trapping and also the surface area available for solubility and mineral trapping. On the other hand, the formation volume that is subject to imbibition at the trailing edge of a migrating plume is dependent only on the volume traced out by the plume and not (at least to first order) on the injection rate or pressure and will therefore generally increase as the well count increases.

Well planning (number, location, and design) Well count As is clear from Table 17.7, well count and injection pressure are strongly linked in the optimization of primary injection. The theoretical minimum number of wells required to achieve a target injection rate can be simply defined based on expected injectivity per well, taking account of processes such as formation drying, halite precipitation, etc., that may cause injectivity to vary through the project life. Injectivity uncertainties and operational considerations, such as well downtime due to maintenance activities, may justify additional wells to ensure that contractual disposal rates can always be achieved. This is analogous to the situation in gas field Table 17.7 Factors affecting injection pressure optimization Injection pressure

Advantages

Disadvantages

Higher pressure

Lower well count to achieve the required injection rate

Increased risk of geomechanical failure in the vicinity of the injection wells Increased cost of injection facilities Higher well count and costs to achieve the required injection rate

Lower pressure

Increased effectiveness of residual trapping in high pressure region Higher well count results in wider areal spread of the plume and increased residual trapping Reduced risk of elevated pressures in near injection wells

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development, where contingency wells are often included in the development plan to ensure that contract quantities can always be delivered.

Well location The two major factors that will influence the subsurface location of injection wells are the impact of localized versus distributed injection on: G

G

Areal pressure response Gross volume swept by the plume and the resulting trapping efficiency

Areal pressure response: an assessment of the magnitude and areal distribution of pressure buildup as a function of injection rate and volume will be an important output from the detailed subsurface modeling work, which will include sensitivity studies to assess the impact of well number and location on the pressure response as well as the influence of the main geological and geomechanical uncertainties. Plume swept volume: the effective residual trapping capacity is determined by the gross rock volume swept by the plume and, unless the host formation is very homogeneous, will generally increase as the number of wells increases. Although geological heterogeneities that will tend to increase swept volume may not be visible in pre-injection seismic, as a general rule a wider areal distribution of injection is likely to increase and accelerate trapping, although at higher cost.

Well design The main design considerations for injection and production project wells are summarized in Table 17.8 and described below. Well trajectory design (vertical, deviated, or horizontal) will be guided by both surface and subsurface factors; for example, surface location constraints may necessitate deviated wells to achieve an areal spread of injection, while horizontal wells may be required to achieve the desired injection rate or to access intermediate-scale reservoir heterogeneity in order to maximize trapping. Table 17.8 Main well design elements for geological storage project wells Well type

Design elements

Injection wells

Well trajectory Tubing size Sandface completion type Material selection Completion requirements for monitoring (sensors, sampling, etc.) Well trajectory Tubing size Sandface completion type Lift requirements (e.g., gas lift) Material selection

Monitoring wells Production (pressure control) wells

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Tubing size will be determined through a joint optimization of four closely related parameters—required rate per well, available injection pressure, host formation injectivity, and sandface completion type. Sandface completion techniques (see Chapter 16) such as hydraulic fracturing or frac-and-pack may be applicable if formation injectivity is a limiting factor. If brine production wells are drilled as part of a preventative or corrective pressure control strategy, artificial lift (e.g., electrical pumping or nitrogen lifting) may be considered in order to achieve the desired production rate. Material selection will be driven by the potential for CO2 corrosion. Injection well components that are only contacted by a dry scCO2 stream will not require special consideration, but components in monitoring and production wells that will come into contact with brine and CO2 will require corrosion-resistant materials.

17.2.2 Pressure control strategies Pressure control strategies may be required as part of the storage plan to control pressure buildup, either in the vicinity of the injection well(s) or more generally throughout the storage complex, in order to reduce or eliminate the risk of leakage. It will be a regulatory requirement to include in the SDP a description of preventative and potential corrective measures that will be taken in the event of significant deviations from expected performance (see, e.g., the EU Directive in Resources). Corrective pressure control measures are discussed in Section 17.3. Preventative measures to control the overall pressure within the storage complex are more likely to be required in the case of a confined host formation, where storage capacity is determined by the maximum allowable pore pressure to prevent geomechanical failure or reactivation of faults or fractures. This control can be achieved by production of brine from the host formation via one or more wells drilled at suitable locations remote from the injection point, with the produced brine either being partially reinjected to enhance trapping (see below), disposed of to an unconstrained aquifer separate from the storage complex or, where environmentally acceptable, to the sea. Chevron’s Gorgon project is one example of a storage project employing pressure management wells, the eight injection wells being supplemented by four brine production wells remote (B5 6 km) from the injection wells, and four reservoir monitoring wells. Disposal of produced brine into an aquifer overlying the storage complex could have a secondary benefit by creating a pressure gradient opposing potential leakage through faults, fractures, or a leaking wellbore. The use of such hydraulic barriers as a corrective pressure control measure is further discussed below. Strategies to limit pressure buildup in the vicinity of injection wells generally rely on increasing the number and spacing of wells, and either operating all wells concurrently or rotating injection among pairs of wells (see Tanaka et al., 2013). This has the disadvantage of increased cost of well construction, but may be required in the event of low permeability of the host formation.

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17.2.3 Trapping control strategies Since residual and solubility trapping are the two trapping mechanisms that can immobilize injected scCO2 on an operational timescale, measures that can enhance the effectiveness of these mechanisms will contribute to both storage optimization and leakage risk reduction.

Enhanced residual trapping Several approaches have been proposed to enhance residual trapping by brine injection, either concurrently with CO2 injection or following the cessation of CO2 injection. Concurrent injection of brine above the point of CO2 injection has been shown in modeling studies to impede upward migration, increase residual trapping both as a result of an increase in the gross rock volume swept by the plume and by an increase and acceleration of imbibition following the cessation of injection (see Nghiem et al., 2009). The enhancement was found to be more pronounced for low permeability formations (kh 5 100 mD) than at higher permeability (kh 5 500 mD). Water injection following the cessation of CO2 injection has also been proposed to enhance residual trapping through forced imbibition (see Spiteri et al., 2005). Injected water will force the breakup of large connected CO2 volumes, increasing residual trapping and immobilization of injected CO2. In combination, the injection of brine both concurrently and following CO2 injection (chase brine) has also been demonstrated in modeling studies to be very effective in rapidly immobilizing injected CO2 as a residual phase (Qi et al., 2009; Huber et al., 2016). The effectiveness of this process depends strongly on the shape of the relative permeability curves, and particularly the imbibition curve that leads to residual trapping (discussed in Chapter 13).

Accelerated solubility trapping Following the cessation of CO2 injection, the production of brine from a region remote from the injection wells and its re-injection into the CO2 plume has been proposed as a strategy to accelerate the dissolution of CO2 (Leonenko and Keith, 2008; Hassanzadeh et al., 2009). The effectiveness of this approach requires good contact between the injected brine and the buoyant plume of free-phase CO2, and it is therefore most applicable in cases where the plume is structurally confined, for example, beneath an anticlinal trap. Figure 17.9 schematically illustrates the process in which CO2 dissolves into CO2 lean injected brine as it descends under gravity through the plume. Modeling studies indicate that under ideal conditions this approach can raise the proportion of injected CO2 trapped by dissolution in the 100 years after the start of injection from 5% or less to around 40%. Clearly this is still a long-term process in relation to the operational life cycle of a storage project, so its application is likely

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CO2

Pump

Overburden ΔH2O Injected CO2

ΔCO2 ΔH2O + ΔCO2

ΔH2O

Aquifer

Figure 17.9 Schematic illustration of accelerated dissolution by brine injection. Source: After Leonenko and Keith (2008).

to be limited to situations where it can mitigate specific long-term risks, such as geochemical alteration of the caprock. Concurrent brine injection above the point of CO2 injection, described in the previous section to enhance residual trapping (Nghiem et al., 2009), has also been shown to effectively enhance solubility trapping on an operational timescale for higher permeability formations (kh 5 500 mD).

17.3

Storage operations and monitoring

This section describes some aspects of the operating phase of a storage project, including performance monitoring (injectivity, storage capacity, conformance, well integrity, etc.) as well as potential corrective and remedial measures that may be required in the event of any deviation from expected performance. An introduction to the wide range of available monitoring and verification technologies is given in Chapter 19.

17.3.1 Operational monitoring Injection plan and storage capacity updates Once the planned injection wells are drilled and tested, the draft injection plan will be updated based on actual well injectivities, and well operating limits specifying the maximum permissible injection rates and pressures for each of the injection wells will be confirmed. A well prioritization list, defining the preferred allocation of injection across the well portfolio in case of CO2 supply shortfall, will be a useful tool to operationalize pressure management and plume footprint considerations.

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Periodic updates to the injection plan and well prioritization will follow in response to monitoring results. As injection and monitoring progresses, insight into the performance of the storage complex will increase, together with confidence in the predictive capability (or otherwise!) of the 3D models. This improving understanding will provide the basis for periodic updates of the capacity estimate for the storage complex. These updates will be particularly important for a utility type storage project, since an increase in the high confidence (e.g., P90) capacity estimate will provide the basis for concluding additional supply/disposal agreements with CO2 producers.

Monitoring plume movement Monitoring activities in the early injection period are important to establish conformance between predicted and observed movement of the plume of injected CO2 and indicate any early deviations, for example, due to geological features that were not evident during initial site characterization. Matching of the observed and predicted plume behavior will enable updating of the flow models and, ideally, a narrowing of the major subsurface uncertainties. If repeated time-lapse 3D seismic surveys are acquired as part of the monitoring program, inversion studies will play an important part in constraining subsurface uncertainties. In such a study, an initial static model is used to predict the expected seismic response, and a comparison between the predicted and actual seismic response provides a constraint on possible values of the most significant subsurface variables. Such studies may indicate the need to update models to incorporate additional formations or features as the performance of the storage complex and connected hydraulic units unfolds (see Jensen et al., 2009).

Well injectivity monitoring In water injection operations for improved oil recovery, well injectivity is often seen to decline as a result of the accumulation of impurities on the face of the injection formation. These are typically corrosion products or particle carryover due to inadequate treatment of source water. For CO2 injection operations the main risk will be the injection of corrosion products in the event that the CO2 is not adequately dried before transportation and injection. Well injectivity can be monitored by recording and comparing injection pressure and injection rate, and an effective tool is the Hall plot, shown schematically in Figure 17.10, in which the product of injection wellhead pressure 3 injection duration is plotted against cumulative injection volume. A linear Hall plot indicates stable injectivity, while upward or downward deviations indicate a reduction or enhancement of injectivity, respectively, due for example to formation impairment or fracturing.

Cumulative wellhead injection pressure x days (MPa·days)

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Rising trend indicates reduced injectivity

Linear trend indicates constant injectivity

Leveling trend indicates increased injectivity

Cumulative injected volume (m3)

Figure 17.10 Schematic Hall plot showing diagnosis of injectivity impairment or enhancement.

17.3.2 Corrective measures and remediation If monitoring results indicate a significant deviation from the expected subsurface performance, for example, unexpected vertical or lateral plume movement, or elevated pressures in monitoring wells, corrective actions may be needed to bring project performance back within permitted limits. The European Commission Directive (2009) on CO2 storage (see Resources) requires project operators to submit a corrective measures plan, identifying measures to be taken in the event of leakage or significant irregularities, and to have this plan approved by the relevant competent authority, as a condition for the award of a storage permit. Operators are subsequently required to notify the competent authority of leakage or significant irregularities and to execute the necessary corrective measures as identified in the plan. Table 17.9 summarizes a range of conditions that would require corrective action, together with measures that could be implemented to remediate these conditions.

Well integrity monitoring and remediation Periodic assessment of well integrity will be required throughout the operating stage of a storage project. Corrosion logging tools can be deployed to determine the condition of casing strings exposed to corrosive fluids, while noise logging can identify intervals where flow is occurring behind casing, for example, if leakage due to cement bond failure is suspected.

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Table 17.9 Significant irregularities necessitating corrective action Significant irregularity

Description

Potential corrective measures

Detection of injected CO2 at surface or in shallow aquifers

Leakage of CO2 outside the storage complex, either through "sealing" formations or along wells

Plume areal extent outside expected range

Plume migrates or is predicted to migrate outside the permitted area

Pore pressure rise outside expected range

Pore pressure exceeds or is predicted to exceed the maximum allowable pressure For example, unexpectedly high surface deformation or micro-seismic activity Loss of injectivity resulting in the need to increase injection pressure to sustain the required disposal rate

Intervention into leaking boreholes to remediate leak paths; reduction of injection rate or cessation of injection; creation of a hydraulic barrier to arrest leakage Reduction of injection rate or cessation of injection; modification of the hydrodynamic regime to influence plume migration; modification of injection well pattern Reduction of injection rate or cessation of injection; production of brine or back-production of CO2 from the host formation Reduction of injection rate or cessation of injection

Results of monitoring surveys outside expected range Decline in well injectivity

Well stimulation depending on diagnosed impairment mechanism; e.g., removal of corrosion products, dissolution of halite deposit, etc.

In the event that well monitoring indicates a loss of integrity, a risk assessment would be conducted to determine whether the well condition warrants a remedial intervention. For example, the risks associated with cement bond failure would be very different for an operating injection well and a monitoring well that is not expected to be intersected by the CO2 plume. Well leakage remediation options, described in Chapter 16, may be essential in the former case, but are less likely to provide costeffective risk mitigation in the latter.

Corrective pressure control strategies Pressure control strategies are corrective measures that can be applied to reduce or reverse fluid flow in natural or engineered flow paths, for example, to prevent undesirable CO2 movement along partially sealing faults or through areas of caprock heterogeneity, and are likely to be a major component of the corrective measures plan. The range of corrective pressure control options available is quite broad and can address pressure and flow anomalies on both local and storage complex wide scales. These strategies are introduced in Table 17.10 and described below.

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Table 17.10 Summary of remedial pressure control strategies Pressure control strategy

Description and application

Production of brine from the host formation

Pressure relief by production of brine from the host formation; also discussed above as a preventative pressure control measure Pressure relief by partial back-production of the injected CO2 from the host formation Modification of pressure gradients and consequent plume movement by production and re-injection of brine from/to the host formation Injection of brine at the downstream end of a potential leak path to create a pressure gradient opposing leakage

Back-production of injected CO2 Modification of the hydrodynamic regime Creation of hydraulic barriers to prevent leakage

Production of brine from the host formation Production of brine from the host formation can be employed both as a planned (i.e., preventative) measure to manage pressure within a confined storage complex and also as a corrective measure in the event of unexpected pressure buildup. The location of brine production will depend on whether pressures need to be reduced at a specific location, e.g., to reduce local fault leak or reactivation risk, or more widely to reduce overall pressure buildup in the storage complex. Pressure relief could be achieved using pre-drilled production wells, the conversion of existing monitoring wells to producers, or the drilling of new dedicated pressure relief wells. Brine from the host formation could be either produced to surface and subsequently disposed of, or possibly “dump flooded” from the host formation into a permitted pressure relief formation.

Back-production of injected CO2 from the host formation Back-production of injected CO2 from the host formation could also be considered as a remedial measure to relieve excessive pressure buildup. The volume of injected CO2 that can be back-produced will depend strongly on its distribution within the host formation. For example, in the case of a contiguous accumulation in a structural trap, considerations of sweep efficiency and residual saturation will be relevant—analogous to the recovery process and efficiency in a hydrocarbon reservoir. However, if injected CO2 is more unevenly distributed, for example, as a result of internal geological heterogeneities (such as the discontinuous horizontal shale layers in the Utsira aquifer at Sleipner—see next section) the back-producible volume will depend on the proportion of injected CO2 that can be accessed by a limited number of production wells.

Modification of the hydrodynamic regime The pressure field resulting from simultaneous production and injection in the region surrounding the plume can be used to modify a pre-existing hydrodynamic regime, and this could be applied as a corrective measure to control the direction of

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plume movement, for example, to prevent the plume approaching an area of increased leakage risk. This approach, either as a preventative or corrective measure, could be applied if a cluster of legacy wells pose a significant leakage risk. Brine injection within the well cluster would prevent plume migration into this area and could be a viable alternative to remedial work on a large number of wells.

Creation of a hydraulic barrier to remediate leakage Leakage through faults, fractures, or wellbores can potentially be remediated by the injection of brine close to the point where the leak path emerges into the overlying permeable formation. The shallow injection establishes a pressure gradient opposed to the leakage direction, in effect creating a hydraulic barrier (see Re´veille`re and Rohmer, 2011). If the injected brine is produced from the storage complex the effectiveness of this strategy will be increased as brine production from the complex will also reduce the driving pressure behind the leakage. Figure 17.11 illustrates the concept and shows an example from modeling studies of the potential impact of a leaking injection wellbore. The subsurface configuration is shown on the left of the figure, while on the right, the solid curve illustrates the leak rate without corrective action, and the dashed curves show the impact of a hydraulic barrier implemented at two different times, which can effectively halt leakage within a few years. Under the conditions described by Re´veille`re and Rohmer, the implementation of this corrective measure can reduce total leakage volume by . 90%, depending primarily on the time delay between the cessation of primary injection and the initiation of remedial injection. Additional hydraulic controls, such as brine injection at the upstream end of a leakage path (i.e., below a caprock leak path), have also been shown in modeling studies to be effective in contributing to leakage remediation by sweeping mobile CO2 away from the leak path (see Zahasky and Benson, 2016).

1.0

100

200

Brine corrective injection well

CO2 storage injection well

Leak path along well into overlying aquifer Caprock Storage aquifer

300

Relative leak rate

Thickness (m)

0

0.75 Unremediated leak rate

0.50

0.25 Leak rate with corrective action

0 0

5

10 Time (years)

Figure 17.11 Impact of a hydraulic barrier on leakage rate. Source: After Re´veille`re and Rohmer (2011).

15

20

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17.4

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Saline aquifer storage case studies

The three case studies described in the following sections have been selected because each offers unique insights into important aspects of saline aquifer storage project planning and operations: 1. Shell Canada’s Quest project is included for the wealth of information available on the project’s knowledge sharing site concerning the initial stages of site selection, storage development planning and MMV planning, and project operations 2. Statoil’s Sleipner project and the Saline Aquifer CO2 Storage (SACS) programs for wealth of learning and best practices on storage performance monitoring and evaluation 3. The Ketzin Storage Pilot as one of the few saline aquifer storage projects that has executed site closure and post-closure activities.

Together they provide a useful learning set across the full life cycle of a saline aquifer storage project.

17.4.1 Saline aquifer storage case study 1: Quest Shell’s Quest project is the first commercial-scale CCS project operating in an industrial processing context—in this case a bitumen upgrading plant at Scotford in Alberta, Canada. The project, which commenced injection in November 2015, captures up to 1.2 Mt-CO2/year from a syngas stream using Shell’s proprietary amine capture technology. The hydrogen product stream is used to upgrade bitumen mined from the Athabasca oil sands, while the captured CO2 is compressed, dehydrated, and transported via an 84 km 12v dense-phase pipeline to be injected into the Basal Cambrian Sands at a depth of about 2.1 km. The injection facility includes three injection wells, providing redundancy to ensure high availability, and the pipeline has been sized for up to 3 Mt-CO2/year to provide capacity for later expansion of the upgrading and capture project. The storage monitoring plan included the drilling of three deep monitoring wells and three shallow groundwater wells, at offset locations from each of the injection wells. One unique aspect of this commercially driven project is the open-access publication of major project documents. This open approach was adopted to enable knowledge sharing and the documents provide a rich knowledge base on which other storage project operators can build (see Resources). Some key features of the Quest SDP and MMV plan are described below, while other useful project documents available online include the Environmental Assessment, independent project review of the storage component by Det Norske Veritas (DNV), and the Closure Plan.

Quest storage development plan The Quest SDP is a comprehensive textbook example of such a document, and its structure and notable contents of each chapter are summarized in Table 17.11.

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Table 17.11 Summary of structure and contents of the Shell Canada Quest project SDP No. Chapter

Summary of contents

1

Executive Summary

2

The Quest Opportunity

3

HSSE and SD

4

Capture Site (Facilities)

5

Storage Site and Well Site Selection

6

Pipeline

7

Integrated Project Design

A high-level overview of the main project parameters, planning assumptions, and value (e.g., economics, if relevant) Describes the project at the next level of detail. What are the key objectives—what does success look like? What are the major components of the project? Overview of the plan to mature and execute the project. Summary of risk management and external stakeholder management plans—including regulatory and permitting requirements. Summary of project costs and economic value (where relevant) Describes the main Health, Safety, Security, and Environmental (HSSE) aspects of the project, as well as its approach to Sustainable Development (SD). Describes the environmental and other regulatory requirements for permitting Describes the engineering concept to be applied at the CO2 capture site, and the design basis of the major facility components, including delivery specification of product streams Describes the process of storage site selection including selection criteria and appraisal workplan execution and outcome. Similarly describes the process for selection of well locations for injection, deep monitoring, and shallow groundwater wells, both firm project wells and future contingency wells Describes the pipeline system, including pipeline design, metering and control systems, interfaces to capture system and wells, pipeline route selection, project construction schedule, and regulatory and land acquisition issues Describes the overall operating limits of the system and how these integrate limits and requirements from subsurface (e.g., fracturing geomechanics), operational (e.g., flow assurance), and engineering design (e.g., compression and pipeline specification) perspectives (Continued)

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Table 17.11 (Continued) No. Chapter

Summary of contents

8

Containment, Storage Capacity, Injectivity, and Conformance

9

Well Engineering and Production Technology

10

Measurement, Monitoring, and Verification (MMV)

11

New Technology Application

12

Asset Management

13

Project Execution Strategy

14

Start-up and Commissioning

15

Closure, Post-closure, Decommissioning, and Abandonment

Describes the storage complex and initial capacity and injectivity assessment. Describes in detail the main site specific risks to each of these factors (containment, capacity, injectivity, and conformance) within the overall risk management framework for the project, as well as risk reduction and mitigation measures (safeguards) Describes the design, construction (drilling and completion), and operation of each of the project well types. Considerations regarding well startup, well interventions, and eventual abandonment are noted, although these activities will be subject to separate detailed planning Provides a general description of the approach to MMV requirements and planning, including the link to the risk management framework, as well as a high-level summary of the MMV plan activities. Effectively an Executive Summary of the more detailed MMV plan A summary of new technologies being applied across all aspects and phases of the project, from the capture facilities to the subsurface surveillance Describes how the project facilities will be operated and maintained after start-up, including the organizational requirements Describes how the project will be executed, including aspects such as project governance, budgeting and cost control, contracting and procurement, assurance, management of change, and risk management during the execution phase Summarizes specific considerations for the start-up of wells and other facilities, which will be covered by separate detailed plans Summarizes considerations for site closure and later stages, including site closure performance targets. Detailed Closure and Post-Closure Plans will be prepared toward the end of the operating phase

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Quest measurement, monitoring and verification plan The Quest MMV plan provides another excellent learning example of the structure and content of a comprehensive MMV plan. Starting from a statement of the purposes and design principles of MMV, the risks to containment and conformance prior to any MMV activities are then described, including an assessment of the natural safeguards in place (e.g., secondary seals, auxiliary storage formations) that contribute to risk reduction. Monitoring technologies to address these risks are identified and a time schedule and coverage plan for data acquisition is constructed, together with performance targets for each selected monitoring technology (see Figure 17.7 for an overview of the MMV design process). Additional contingency monitoring activities are then identified, together with the trigger levels to initiate these activities. These activities would either be triggered in response to underperformance of the base plan monitoring technologies, in the case of safety critical containment monitoring, or triggered by deviations from expected performance in the case of conformance monitoring. A time schedule and coverage plan for acquisition, as well as performance targets, are specified in the same way as for the primary MMV activities. The document then describes the residual risks after MMV activities, showing how these additional safeguards contribute to risk reduction.

17.4.2 Saline aquifer storage case study 2: Sleipner In the Norwegian sector of the North Sea, Statoil and partners have been producing natural gas from the Sleipner East and West fields since August 1996. The Sleipner gas contains 4.0% 9.5% CO2, which had to be reduced to , 2.5% to meet the EU pipeline gas delivery specification. In the absence of an economic EOR opportunity, the overlying Utsira aquifer was identified as a CO2 disposal reservoir. Figure 17.12 shows a schematic of the project. Similar to the Weyburn EOR example discussed in the next chapter, an international multidisciplinary research program was established to collect and analyze data from the project and to leverage this to provide guidance for similar projects in the future. The SACS and subsequent SACS2 programs ran from 1998 to 2003 and culminated in the publication of a Best Practice Manual (see StatoilHydro, 2003 in Resources) based on the knowledge gained and lessons learned in this project.

Site characterization and selection The Utsira formation is an unconsolidated water-bearing sandstone with high porosity (30% 42%) and permeability (1 3 3 10212 m2 (1 3 Darcy)). Initial characterization of the aquifer, which is . 400 km long and 50 100 km wide, was based on an extensive regional 2D seismic dataset, as well as data from some

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Sleipner platform and processing facilities

Utsira formation

Gas production wells

CO2 plume

CO2 injection well

Gas reservoir

Figure 17.12 Schematic overview of the Sleipner CO2 storage project. Source: Courtesy, Statoil.

300 well penetrations, of which 30 were within 20 km of the selected injection location. At the Sleipner field the Utsira formation lies at a depth of 800 m, deep enough for CO2 to remain in a supercritical state, and forms an almost flat structure with a gentle dip to the south and southwest. This type of structure poses specific problems for predicting plume movement, since minor changes in the topology of the caprock can have a significant impact on the migration direction of the injected CO2. In this situation accurate depth mapping of the top structure is essential, based on dense 2D or 3D surveys tied to adequate well data. This would be less of an issue in formations with high-relief structural or stratigraphic traps, where plume movement will be more constrained by these geological features. To minimize the risk from potential leak paths, the injection site was chosen to ensure that predicted migration of the plume would take it away from the gas production wells, and a small structural trap in the aquifer was selected as the injection target. Preliminary reservoir modeling work indicated that a plume with a maximum lateral extent of 3 km would be formed after 20 years of injection.

Injection operation and monitoring Capture of B1 Mt-CO2/year using amine stripping and injection into the single disposal well commenced in September 1996. A 3D survey acquired in 1994 was used as the baseline for monitoring, and repeated time-lapse (4D) surveys acquired roughly every 2 years since 1999 have provided a detailed picture of the evolution of the plume. The survey results (Figure 17.13) show that the vertical movement of CO2 was impeded by small-scale impermeable shale layers that were below the resolution of

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CO2 plume in map view

2001 Increasing amplitude

1994

1 km

Injection point 2008

1994 – 2008

1999 2001 2002

2004

2006

2008

Figure 17.13 Sleipner time-lapse seismic results. Source: Courtesy, Statoil.

Top Utsira formation Discontinuous shale layers Rising CO2 plume Base Utsira formation

Injection point

Figure 17.14 Schematic plume evolution controlled by thin shale layers.

the seismic. These layers caused lateral spreading of the buoyant fluid, which then spilled at permeable boundaries and rose to the next thin layer (Figure 17.14). The 4D seismic results could be well matched in the reservoir simulation once these fine-scale details were incorporated into the geological model. In the longer term (.50 years) all mobile CO2 is expected to migrate to the top of the formation, and the caprock topology will be the geological feature controlling further evolution of the plume. These results demonstrated the central role of timelapse seismic in monitoring geological storage operations, as well as the potential for plume dynamics and CO2 trapping to be significantly affected by small-scale geological heterogeneities that may not be recognized or represented in the initial geological dataset. The Utsira aquifer, with an estimated storage capacity of 15 Gt-CO2, has been identified as a potential host formation for a regional carbon storage facility which could accommodate injection of up to 300 Mt-CO2/year for 50 years. Effective subsurface modeling on this scale—incorporating sufficient resolution and process detail in a model extending over tens of thousands of square kilometers—is a major

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R&D challenge (see Gasda et al., 2017) that will provide valuable guidance for similar basin-scale projects in other regions.

17.4.3 Saline aquifer storage case study 3: Ketzin pilot The Ketzin pilot, located 25 km west of Berlin, Germany, was the first onshore saline aquifer storage pilot in Europe. Research activities, initially funded under the EU’s CO2SINK project, began at the site in 2004, with the drilling of one injection well and two observation wells. An extensive monitoring program, including the drilling of additional observation wells for above zone monitoring and to core the reservoir and caprock, was conducted during the injection period from June 2008 to August 2013, when some 67 kt-CO2 was injected into a saline aquifer at B650 m depth. In January 2014, the COMPLETE project was started at Ketzin, with the objective of capturing the knowledge and experience of the final phase in the life cycle of a saline aquifer storage site. The project scope covers three main themes: 1. Operational activities involved in well abandonment and site decommissioning 2. Post-closure monitoring activities including a repeat 3D seismic survey, electrical and surface CO2 flux measurements 3. Simulation model updates to support the post-closure monitoring campaigns

The latter theme will also include the integration of extensive project datasets into a single long-term archive. Some additional field experiments are also planned, including an investigation of physico-chemical properties of back-produced CO2 and a brine injection test to assess residual gas saturation and to test brine injection as a possible remedial measure in the event of wellbore leakage (see above). While it is less relevant for pilot-scale operations, regulatory requirements for site closure at a commercial-scale site (.1 Mt-CO2/year) will include a demonstration that the agreed performance criteria for site closure have been met, a formal assessment of post-closure risks and an update of the MMV plan to address those risks during the post-closure period, prior to the transfer of long-term responsibility to the relevant agency. An example of this closure plan documentation is available online for the Shell Quest project (see Resources).

17.5

R&D for saline aquifer storage

Technologies developed in the oil and gas industry have enabled saline aquifer storage projects to proceed rapidly to the demonstration stage, but many of the geomechanical and geochemical processes and monitoring requirements for these projects represent a step-out from oil and gas field practice and are the subject of ongoing RD&D work. These and other RD&D themes for saline aquifer storage are summarized in Table 17.12.

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Table 17.12 RD&D themes for saline aquifer storage RD&D theme

Description

Trapping mechanisms

Evolution of residual saturation after injection and linkage with solubility and mineral trapping; lab-scale (sandbox) experiments to investigate trapping mechanisms and test trapping enhancement strategies; high-resolution scanning techniques (X-CT, PET, etc.) to investigate flow and trapping behavior in cores Improvements in imaging technologies to quantify plume location, saturation, and volumetrics, monitor caprock integrity, and enable leak detection; resolution improvements, e.g., imaging small-scale heterogeneities, spatial location of microseismic events; techniques to optimize monitoring networks Reaction of CO2 with reservoirs and seals—impact on caprock wettability, entry pressure, and self-sealing potential; processes in carbonate formations; mineral trapping, including in situ mineral carbonation; dissolution and mobilization of heavy metals or other potential contaminants; validation of reactive transport models Impact of injection pressures and temperatures on reservoir and caprock, faults, and fracture networks, including low-temperature injection from ship-borne CO2; long-term impact of CO2 on caprock mechanical properties; formation creep as a leak healing mechanism Development of efficient tools and automation technologies for real-time integration of subsurface and surface monitoring data, and comparison against baseline surveys; new techniques for leak detection Incorporate improved process knowledge into mathematical simulation models; improved modeling of fault flow processes and in situ validation; simplified coupled hydrodynamic-geomechanical models to enable regional-scale studies

Subsurface monitoring and imaging

Geochemical processes

Geomechanical processes

Operational technologies

Subsurface modeling

17.6

References and resources

17.6.1 References Brunsting, S., De Best-Waldhober, M., Feenstra, C.F.J., Mikunda, T., 2011. Stakeholder participation practices and onshore CCS: lessons from the Dutch CCS case Barendrecht. Energy Procedia. 4, 6376 8383. CO2STORE, 2008. Best practice for the storage of CO2 in saline aquifers. In: Chadwick, A., Arts, R., Bernstone, C., May, F., Thibeau, S., Zweigel, P. (Eds.). British Geological Survey, Nottingham, UK.

Saline aquifer geological storage

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Chevron, 2005. Environmental Impact Statement/Environmental Review and Management Programme for the Gorgon Development. Chevron Australia. Cooper, R.G., 2008. The stage-gate idea-to-launch process update, what’s new and NexGen systems. J. Prod. Innov. Manage. 25, 213 232. FutureGen, 2007. FutureGen initial conceptual design report. Report PNWD-3760, FutureGen Alliance, Washington, DC. Gasda, S.E., Wangen, M., Bjørnava˚, T.I., Elenius, M.T., 2017. Investigation of caprock integrity due to pressure build-up during high-volume injection into the Utsira formation. Energy Procedia. 114, 3157 3166. Gerstenberger, M., Nicol, A., Senhouse, M., Berryman, K., Stirling, M., Webb, T., et al., 2009. Modularised logic tree risk assessment method for carbon capture and storage projects. Energy Procedia. 1, 2495 2502. Govindan, R., Elahi, N., Korre, A., Durucan, S., Borda, E.S., 2017. The development of a dynamic CO2 injection strategy for the depleted Forties and Nelson oilfields using regression-based multi-objective programming. Energy Procedia. 114, 3335 3342. Hassanzadeh, H., Pooladi-Darvish, M., Keith, D.W., 2009. Accelerating CO2 dissolution in saline aquifers for geological storage—mechanistic and sensitivity studies. Energy Fuels. 23, 3328 3336. Huber, E.J., Stroock, A.D., Koch, D.L., 2016. Analysis of a time dependent injection strategy to accelerate the residual trapping of sequestered CO2 in the geologic subsurface. Int. J. Greenhouse Gas Control. 44, 185 198. IMO (International Maritime Organization), 2007. Specific guidelines for assessment of carbon dioxide streams for disposal into sub-seabed geological formations. London Convention Report LC/SG 30/14, Annex 3. Jensen, G.K.S., Nickel, E.H., Whittaker, S., Rostron, B.J., 2009. Geological model and hydrogeological framework of an active CO2 sequestration project in the WeyburnMidale area, Saskatchewan: leading to a further understanding of possible CO2 migration. Energy Procedia 1, 2983 2989. Leonenko, Y., Keith, D.W., 2008. Reservoir engineering to accelerate the dissolution of CO2 stored in aquifers, American Chemical Society. Environ. Sci. Technol. 42, 2742 2747. Martens, S., Mo¨ller, F., Streibel, M., Liebscher, A., the Ketzin Group, 2014. Completion of five years of safe CO2 injection and transition to the post-closure phase at the Ketzin pilot site. Energy Procedia. 59, 190 197. NETL, 2010. Best practices for site screening, selection, and initial characterization for storage of CO2 in deep geologic formations. National Energy Technology Laboratory Report DOE/NETL-401/090808. Nghiem, L., Yang, C.D., Shrivastava, V., Kohse, B., Hassan, M., Card, C., 2009. Risk mitigation through the optimization of residual gas and solubility trapping for CO2 storage in saline aquifers. Energy Procedia. 1, 3015 3022. Oldenburg, C.M., 2008. Screening and ranking framework for geologic CO2 storage site selection on the basis of health, safety, and environmental risk. Environ. Geol. 54, 1687 1694. Qi, R., LaForce, T.C., Blunt, M.J., 2009. Design of carbon dioxide storage in aquifers. Int. J. Greenhouse Gas Control. 3, 195 205. Re´veille`re, A., Rohmer, J., 2011. Managing the risk of CO2 leakage from deep saline aquifer reservoirs through the creation of a hydraulic barrier. Energy Procedia. 4, 3187 3194. Ringrose, P., Greenberg, S., Nazarian, B, Oye, V., Whittaker, S., 2017. Building confidence in CO2 storage using reference datasets from demonstration projects. Energy Procedia. 114, 3547 3557.

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Senior, B., Bradshaw, J., Chikkatur, A., Wright, M., 2011. Planning saline reservoir storage developments—the importance of getting started early. Energy Procedia. 4, 4575 4582. Spiteri, E.J., Juanes, R., Blunt, M.J., Orr, F.M., 2005. Relative permeability hysteresis: trapping models and application to geological CO2 sequestration. Society of Petroleum Engineers (SPE 96448). 2005 SPE Annual Technical Conference and Exhibition, Dallas, TX. Tanaka, K., Vilca´ez, J., Sato, K., 2013. Improvement of CO2 geological storage efficiency by injection and production well design. Energy Procedia. 37, 4591 4597. Walkup, G.W., Ligon, J.R., 2006. The good, the bad, and the ugly of the stage gate project management process in the oil and gas industry. Society of Petroleum Engineers (SPE 102926). 2006 SPE Annual Technical Conference and Exhibition, San Antonio, TX. Zahasky, C., Benson, S.M., 2016. Evaluation of hydraulic controls for leakage intervention in carbon storage reservoirs. Int. J. Greenhouse Gas Control. 47, 86 100.

17.6.2 Resources Allen, R., Nilsen, H.M., Andersen, O., Lie, K.-A., 2017. Categorization of Norwegian Continental Shelf formations in terms of geological CO2 storage potentials. Energy Procedia. 114, 4583 4594. CO2 Storage Data Consortium (CSDC—an international network to promote sharing of data and knowledge from CO2 storage projects): www.sintef.no/en/sintef-petroleum-research/ csdc2016. CO2MultiStore project (project addressing issues related to the development of multi-user regional storage sites): www.sccs.org.uk/expertise/reports/co2multistore-joint-industryproject. European Commission Directive, 2009. Directive on geological carbon storage: eur-lex. europa.eu/LexUriServ/LexUriServ.do?uri5OJ:L:2009:140:0114:0135:EN:PDF. DNV (recommended practices for geological storage): www.dnvgl.com/oilgas/download/dnvrp-j201-j202-j203-dnv-oss-402.html. IEAGHG, 2015. Review of offshore monitoring for CCS projects. IEAGHG Report 2015/02, IEAGHG, Cheltenham, UK. Ketzin pilot project: www.co2ketzin.de/nc/en/home.html. Product Development Institute (information on the stage gate project management process): www.prod-dev.com/stage-gate.php. Shell International B.V., 2015. The Quest for less CO2: learning from CCS implementation in Canada. A case study on Shell’s Quest CCS Project. Shell Quest Knowledge Sharing site: www.energy.alberta.ca/CCS/3848.asp, including 2012 MMV Plan (www.energy.alberta.ca/CCS/4043.asp#Shell) and 2013 update of the Closure Plan (www.energy.alberta.ca/CCS/CCS_Docs/Closure_Plan_Third_Year_Update.pdf). StatoilHydro, 2003. Best Practice Manual from SACS: Saline Aquifer CO2 Storage Project. Available at www.co2store.org, SACS project page. Strategic UK CCS Storage Appraisal Project (assessment of UK North Sea carbon storage potential): www.eti.co.uk/programmes/carbon-capture-storage/strategic-uk-ccs-storageappraisal. Sijacic, D., Wildenborg, T., Steeghs, P., 2014. TNO monitoring plan development tool. Energy Procedia 63, 4834 4840. US DOE/NETL Carbon Storage Program offshore CCS assessment (see Rodosta, T., Bromhal, G., Damiani, D., 2017. US DOE/NETL Carbon Storage Program: advancing science and technology to support commercial deployment. Energy Procedia. 114, 5933 5947.

Other geological storage options

18

Apart from saline aquifer storage, most of the options for subsurface carbon storage are related to producing or depleted oil and gas fields. This chapter therefore begins with a brief introduction to oil and gas recovery as a precursor to the discussion of these options. Non-hydrocarbon related geological storage options are then reviewed.

18.1

Oil and gas reservoir exploitation

The fraction of the oil or gas initially in place that can be economically recovered from a given reservoir depends on a wide range of factors, including the fluid and rock properties, the areal and vertical variability of rock properties, and the presence of an active aquifer connected to the formation, which may provide pressure support when hydrocarbons are withdrawn. Primary oil recovery results from production under pressure depletion, in which the reservoir pressure declines as fluids are withdrawn, or with pressure support from an aquifer. In this phase, the recovery of oil can range from 10% to 20% of the original oil in place (OOIP) in the case of pure pressure depletion up to 50% 60% or occasionally higher for reservoirs with pressure support from a natural aquifer. In the absence of pressure support from an aquifer, water or gas injection may be used to maintain reservoir pressure. These so-called secondary recovery methods can increase primary depletion recovery to 30% 50% as a result of sustained production levels and improved sweep of oil out of the rock pores as the injected water or gas pushes the oil saturation down toward the residual value. Since the influx of a natural aquifer can occur along the whole oil water boundary while injection takes place only at a number of discrete points, the former is generally more efficient at reaching the parts of the reservoir that secondary recovery methods cannot reach, resulting in higher recovery efficiencies. In gas reservoirs, the higher mobility of gas compared to oil and the drive energy available from expansion of the compressed gas result in primary recoveries that can reach 90% 95%. Gas recovery is generally higher if the reservoir pressure is not maintained since, from simple gas law considerations (pV 5 znRT), the amount of unrecovered gas remaining in a given pore volume declines as the abandonment pressure is reduced. Rather than injecting fluids into the reservoir, gas recovery is usually maximized by installing compressors at surface, so that the gas can be produced down to the lowest possible abandonment pressure. However, if the reservoir fluid in a gas reservoir is susceptible to retrograde condensation (the condensation of heavier hydrocarbon components to form an in situ liquid phase as reservoir pressure declines), maintenance of reservoir pressure above the dew point will increase the recovery of these high-value components. This is Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00018-0 © 2017 Elsevier Inc. All rights reserved.

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typically achieved by an initial stage of gas recycling, in which lean gas is reinjected into the reservoir after condensate has been stripped out at the surface. Once condensate production drops as a result of the breakthrough of the recycled lean gas, reinjection will cease and the reservoir will be produced under pressure depletion.

18.2

Enhanced oil recovery

When primary and secondary recovery schemes have run their course, oil recovery can be further enhanced by the application of tertiary recovery methods, of which the most common are steam injection, which is applied to heavy viscous crude oils, or CO2 injection. EOR by CO2 flooding is applicable to reservoirs deeper that B800 m, at which depth hydrostatic pressure reaches the CO2 critical pressure of 7.38 MPa, and for crude oils with a density of less than B0.9 at 15 C. Under these conditions, dissolution of supercritical CO2 increases the mobility of the residual oil in the formation by increasing its volume, and saturation, and reducing its viscosity. From a CCS perspective, depths greater than 800 m also enable high storage efficiency by storing CO2 as a dense supercritical fluid. For pressures above 10 15 MPa, depending on oil composition and temperature, CO2 and crude oil will become fully miscible, resulting in improved mobilization and sweep of remaining oil toward production wells, as illustrated in Figure 18.1. The produced CO2 plus crude oil mixture is separated in surface facilities yielding oil, hydrocarbon gas, and CO2 product streams. The injection of CO2 to enhance recovery from oil fields (EOR) was field-tested in the 1960s and has been commercially applied since 1972, when the CO2-EOR project commenced in the SACROC Unit of the West Texas Kelly-Snyder field. Oil and gas delivery

CO2 supply

Injection Production separation well CO2 recycle and CO2 recovery

CO2 bank

CO2 miscible oil bank oil bank

Figure 18.1 Configuration of EOR by miscible CO2 flooding.

Production well

Other geological storage options

473

CO2 injection has since become widespread as an EOR technique, particularly in the Permian Basin in west Texas and southeast New Mexico, where plentiful CO2 has been available at low cost from the large natural accumulations in Colorado and New Mexico. Incremental oil recoveries cover a wide range from 5% to 15% of OOIP, depending on reservoir characteristics and the recovery efficiency of the preceding secondary recovery scheme. Where geological storage is combined with EOR or EGR, the primary containment mechanism will be structural trapping beneath the caprock or other seal that contained the original hydrocarbon accumulation. Solubility trapping will occur both as a result of CO2 dissolution in unswept and residual oil and potentially also in water, provided that the CO2 accumulation is in contact with any underlying aquifer. This may not always be the case in an EOR project, where a remnant oil column beneath the CO2 accumulation may prevent or severely restrict such contact. If CO2 for an EOR flood is purchased, project economics are generally improved by alternating injection of CO2 and water in a so-called water-alternate-gas (WAG) scheme, with the alternating period being anything from days to months. The volume of gas purchased is also minimized by separating CO2 from produced oil and recycling this to the injection wells. If an EOR flood will eventually be used for CO2 storage (after the end of economic oil production), recycling of early breakthrough gas would also be required and storage capacity would be maximized by using continuous CO2 injection rather than WAG, depending on the available volume of CO2 for storage. On the other hand, CO2 availability at zero or potentially negative cost (i.e., including some residual carbon credit after capture and transportation costs) opens up the possibility of large-scale CO2-EOR and storage in oil provinces where this tertiary recovery option might previously have been considered uneconomic. The North Sea is such a province, and a number of recent studies have looked at CO2-EOR potential in maturing North Sea fields, including one study of the Norwegian sector which identified a storage capacity of 1.9 Gt-CO2 in 23 fields, net of the 830 Mt-CO2 resulting from combustion of the incremental oil recovered (Lindeberg et al., 2017).

18.2.1 Unconventional CO2-EOR storage options Injection below depleted oil fields Injection below the oil water contact (OWC) in depleted oil fields has also been proposed as a geological storage option. This is effectively saline aquifer injection, with containment occurring when the injected fluid migrates up to the seal of the original hydrocarbon accumulation. As well as this primary structural trapping, the full range of trapping mechanisms described in earlier chapters for saline aquifer storage would apply to the region below the OWC. EOR can also occur in this situation as a result of mobilization of residual oil and its migration to the crest of the structure, although this will be on a much longer timescale than conventional EOR projects.

Residual oil fairways Similar residual oil targets also occur in many hydrocarbon basins in so-called residual oil zone fairways, which have recently been investigated as a potential new

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type of geological storage target. Residual oil fairways occur within saline aquifers on the paths along which oil migrated over geological time before reaching current oil reservoirs. These fairways typically have high permeability, as they were the preferred flow path, and will generally also have a competent seal, although there may be cases where onward oil migration occurred along faults or where permeability has been reduced by subsequent diagenetic processes. Initial studies reported by Burton-Kelly et al. (2016) and Kuuskraa et al. (2017) suggest that, within the general category of saline aquifer storage formations, these fairways could provide an additional economic incentive for carbon storage through the mobilization and production of otherwise unrecoverable residual oil.

Tight oil reservoir CO2-EOR The recent global surge in oil production from unconventional oil reservoirs (shale oil) opens up the possibility of CO2 storage in these reservoirs. In tight oil producing formations, permeability and therefore injectivity arises almost entirely from the fracture network created by hydraulic fracking, and the oil wet nature and vanishing matrix permeability of these formations makes them unsuitable for secondary recovery by waterflooding. Preliminary laboratory and simulation studies, reported by Sorensen et al. (2017), indicate the potential for significant EOR and CO2 storage, with molecular diffusion being a major driving force.

18.2.2 EOR case studies EnCana Weyburn field The largest EOR project to date using anthropogenic CO2 is the EnCana Weyburn project, which began injecting CO2 from a synfuels gasification plant in September 2000, together with the Apache Canada operated Midale field which began injection in 2005. The combined project involves the transport of over 2.2 Mt-CO2/year (6000 t-CO2/day) of 96% pure, supercritical CO2 from a coal gasification plant in North Dakota, USA, through a 325 km pipeline to the Weyburn/Midale fields in Saskatchewan, Canada. The CO2 is injected into the Midale fractured carbonate formation at a depth of 1400 1500 m. Prior to the start of EOR operations, 25% of the Weyburn field’s 220 Mm3 of OOIP had been produced by primary recovery and secondary waterflooding and it is estimated that the EOR project will result in an additional recovery of 9% of OOIP, as well as storing 22 Mt-CO2. The Weyburn and Midale units were initially developed using a so-called inverted nine-spot pattern, illustrated in Figure 18.2, in which each injection well is surrounded by eight producers at a grid spacing of approximately 150 m between producing wells. In an extended grid using this configuration, the ratio of producing/ injecting wells is 3 to 1. The Weyburn patterns were subsequently modified to increase oil recovery by the drilling of horizontal wells within the patterns (known as “infill” wells).

Other geological storage options

475

Production wells

Injection wells

Nine-spot pattern

Inverted nine-spot pattern

Figure 18.2 Inverted nine-spot and modified inverted nine-spot well patterns.

The first phase of the EOR project involved CO2 injection into 18 such patterns, extending in subsequent phases to 75 patterns, covering a total area of close to 700 Ha. Through the involvement of the International Energy Authority (IEA), the Weyburn project has become an important demonstrator for geological sequestration in general, not limited to EOR applications. A comprehensive research and study program was launched in 1999, covering four key research themes: 1. 2. 3. 4.

Geological characterization of the site Prediction, monitoring, and verification of CO2 movement after injection Prediction of the technical and economic limits to storage capacity A long-term risk assessment for the site.

Geological characterization Geological characterization of the site includes both the target injection formation and the overburden layers and provides the basis for the construction of an integrated 3D geological model that is used to predict and monitor the performance of the project, both during the injection phase and in the long term. The geological characteristics that must be assessed for a potential site to be considered suitable for storage are summarized in Table 18.1, together with the assessment techniques that can be applied. Since a significant proportion of injected CO2 will eventually be trapped by dissolution in formation water, flow in a dynamic aquifer is a mechanism that could transport CO2 outside the desired boundaries. For this reason the hydrological regime, which is rarely a major issue in oil field operations, including EOR, is a consideration for CO2 storage.

Prediction, monitoring, and verification of CO2 movement To provide assurance of long-term storage it is necessary to be able to predict the lateral and vertical movement of CO2 after injection and then to monitor the actual movement in order to verify these predictions. This verification from monitoring data provides a degree of assurance for the predictions of storage capacity and longer term CO2 movement.

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Table 18.1 Aspects of geological characterization assessed for the Weyburn project Required geological characteristics Description and assessment techniques G

G

G

G

G

Presence of competent sealing boundaries Effective trapping in the target formation Absence of vertical conduits through open faults or fractures Isolation from surface connected aquifers A suitable hydrodynamic regime

G

G

G

G

G

G

G

Regional structural and stratigraphic mapping of the target formation and overburden up to surface Assessment of the regional tectonic activity and the presence and recent activity of any related faulting Stratigraphic interpretation of cores and well logs Rock porosity, permeability, and mineralogy from core samples Integration of all data and interpretations into a 3D reservoir geological model for use in risk assessment and performance prediction and monitoring Identification and evaluation of man-made conduits such as abandoned boreholes Hydrological assessment and distribution of shallow aquifers

In the case of an EOR storage project, this task will be aided by the subsurface geological and dynamic performance data gathered during the primary and secondary recovery phases, and by integrated numerical simulation models that will have been constructed as tools to manage these phases. During EOR operations, this database will be supplemented by a range of additional surface and subsurface monitoring data. The types of data that may be acquired and their application are summarized in Table 18.2.

Prediction of the technical and economic limits to storage capacity Prediction of the technical limit to the storage capacity of an EOR site is an extension of the numerical reservoir simulation work performed for monitoring and verification. The aim of this work is to predict the long-term distribution of CO2 within the reservoir, long after the end of the injection period, and thereby to establish the maximum CO2 volume that can be accommodated while maintaining this long-term distribution within specified boundaries. Valid long-term predictions can only be derived from a reservoir model that is grounded in a detailed understanding of the physical and chemical processes occurring in the reservoir. Laboratory measurements of rock and fluid properties and interactions, including potential changes in these parameters through time, provide the basis for understanding the mechanisms that will trap CO2, and simulation of these processes allows the long-term distribution to be predicted.

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477

Table 18.2 Description and application of CO2 flood monitoring data Monitoring data

Description and application

Pressure and volume measurements during injection and production

Basic data to perform material balance calculations and assess the dynamic response of the reservoir to injection and production Tracing the movement of injected CO2 and identification of reservoir geochemical processes taking place on the timescale of injection, such as carbonate mineral dissolution Starting with a baseline survey before the start of injection, repeated surveys allow tracking of CO2 saturation changes that occur at the flood front Comparison with off-site control measurements to detect CO2 that may have leaked from the reservoir

Geochemical composition of produced fluids, including carbon isotopes

Time-lapse (4D) seismic monitoring surveys Soil gas sampling or laser-based CO2 detection systems

Miscible flood Injection well CO2 bank

Miscible oil

Oil bank CO2 bank

Production well Injection well

Production well Oil bank

CO2 bank

Water CO2 Miscible Oil bank bank oil bank

Miscible flood with WAG

Immiscible flood

Figure 18.3 CO2 distribution during EOR injection phase.

Figure 18.3 illustrates the distribution of CO2 during the injection phase of an EOR project, for both miscible and immiscible conditions. Mixing or dissolution of CO2 in the oil phase will dominate in the flood front, while CO2 will be present as a separate mobile or residual phase behind the front, depending on whether a WAG scheme is employed. When injection ceases, mixing will continue under gravitational and diffusive forces. Free supercritical CO2 will continue to dissolve in both oil and formation water, and density and concentration differences will drive the redistribution of fluids. Geochemical processes involving the removal of CO2 by mineral precipitation (mineral

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Carbon Capture and Storage

trapping) can also occur over a long timescale (see Figure 11.7). Over a millennial timescale, and provided that primary containment in the subsurface is maintained, all free CO2 will eventually be trapped by one of these mechanisms—dissolution in oil or water or by mineral trapping. In the case of the Weyburn project, the predicted outcome of these trapping processes after 5000 years is that B45% of CO2 will be dissolved in the oil phase, with the remainder distributed equally between trapping in water and mineral trapping. In parallel with the technical modeling work, an economic model is constructed to integrate the technical, economical, and fiscal aspects of the project—including the effects of oil price and CO2 costs or credits. This model is used to determine the point at which CO2 injection is no longer economic, for example, as a result of declining oil production, which in turn will determine the economic storage limit of the project. In the Weyburn example, a technical storage limit of over 45 Mt-CO2 was estimated, while the economic limit of the EOR project is expected to be reached after injection of roughly half this quantity. CO2 credits would be required to make the remaining storage capacity economically viable. Modeling predictions are subject to many uncertainties, from measurement uncertainties in the basic data to subsurface heterogeneities on a range of length scales, which are captured using various approximations in the reservoir model. The standard approach to dealing with these uncertainties is to perform sensitivity studies using a number of alternative models to capture the possible ranges of uncertain parameters. The resulting range in predicted results provides one of the key inputs to the final theme—risk assessment.

Long-term risk assessment The objectives of the long-term risk assessment are threefold: 1. to identify the mechanisms that could lead to the leakage of CO2 from the target storage reservoir into the biosphere, comprising shallow potable aquifers, surface soil, and the atmosphere, 2. to assess the likelihood and consequences of leakage as a result of these mechanisms, and 3. to identify any mitigating actions that may be needed to reduce these risks to an acceptable level.

Formal risk analysis tools are applied, which build on an inventory of the relevant characteristics, events, and processes to define a range of possible scenarios for the future performance of the system. A non-exhaustive example of a risk assessment input listing is shown in Table 18.3. Quantitative risk assessment, applying probabilistic methods, can be used to estimate the probability of containment within or movement out of the target reservoir, including the volume and probability range for CO2 leakage into the biosphere. In the Weyburn risk assessment, it was estimated with 95% confidence that from 98.7% to 99.5% of the CO2 in place at the end of the EOR injection phase would remain stored in the geosphere and that the mean leakage through abandoned wells would be less than 1025 of the stored volume.

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Table 18.3 Typical risk assessment process input Characteristics G

G

G

G

G

Primary caprock properties and extent Presence and abandonment status of old boreholes Presence, potential conductivity, and recent activity of nearby faults Presence and extent of saline aquifers above the primary caprock Hydrology of groundwater system

Events G

G

G

G

G

G

Start of CO2 injection Earthquake occurrence Fault reactivation Construction of new boreholes Loss of integrity of production and injection wells or other boreholes Maintenance (workover) activity on existing wells

Processes G

G

G

G

G

G

Pressure driven flow of injected CO2 Pressure driven flow of any dynamic aquifers, including deep saline and fresh groundwater Density-driven convective flow of fluids Dissolution or precipitation of minerals Diffusion of CO2 Microbial activity

The approaches described above, which were developed as part of the IEA Weyburn project, provide a framework for assessing the long-term storage aspects of CO2 flood EOR projects and are also for the most part applicable to other storage options such as saline aquifer storage described below.

18.2.3 Planned EOR sequestration projects With incremental oil revenues providing a helpful economic incentive, EOR-based projects will continue to provide a foundation for the demonstration of capture technologies, as well as providing opportunities to further develop and test subsurface modeling and monitoring techniques. Current status of projects can be found in the Global CCS Institute database (see Resources).

18.3

Enhanced gas recovery

Gas reservoirs share many of the advantages enjoyed by oil reservoirs as potential CO2 storage sites, particularly in relation to the availability of reservoir characterization data and the presence of a demonstrated caprock. In gas reservoirs this is often more strongly demonstrated than in oil reservoirs as a result of the higher overpressure acting against the caprock that arises from the density difference between gas and water, as illustrated in Figure 18.4. As noted above, maintaining pressure by fluid injection into gas reservoirs generally does not increase recovery, although pressure maintenance by gas recycling

Carbon Capture and Storage

Vertical depth below sea level (m)

480

Gas gradient

2400 2420

Oil gradient

2440 2460

Water gradient

2480 2500

25.0

25.2

25.4

25.6

25.8

Pressure (MPa)

Figure 18.4 Pressure gradients in oil and gas reservoirs.

may be applied in order to avoid a loss of condensate recovery if the reservoir fluid is subject to retrograde condensation in the reservoir. However, as a gas reservoir approaches abandonment, CO2 injection can yield EGR by repressurizing and sweeping residual gas toward production wells. Due to the density and viscosity differences, the sweep of methane by supercritical CO2 will be stable so that, depending on the configuration of injecting and producing wells, it should be possible to fill the greater part of the reservoir volume with CO2 before breakthrough into the producing wells occurs.

Active EGR pilot project—K12-B field, North Sea, Dutch sector A pilot-scale EGR project was started in the K12-B gas field in the Dutch sector of the North Sea in 2004. The field, operated by Gaz de France, was discovered in 1981 and contained 14.4 Gm3 of gas, with 13% CO2 content, in fluvial and eolian Rotliegend sandstones at a depth of B3900 m. CO2 is separated at surface by amine stripping and from 1987, when the field was brought on stream, until 2004 all produced CO2 was vented. During this period 11.5 Gm3 of gas was produced and reservoir pressure dropped from 40 to 4 MPa. An EGR opportunity was identified in 2001, and detailed geological characterization and model building studies were completed as part of the feasibility and pilot planning phase. A particular focus of these studies was evaluation of the impact of the large historical reservoir pressure drop on formation injectivity and on the sealing capacity of the Zechstein evaporite caprock. Feasibility studies concluded that the field was suitable for CO2 storage and a small-scale pilot consisting of two injection tests was initiated in 2004, as summarized in Table 18.4. Although there was no clear demonstration of EGR from these tests, a further phase of monitoring and investigation under the MONK project (Monitoring K12-B) was commenced in 2007.

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Table 18.4 K12-B pilot injection test scope Pilot test

Description

Test objectives and outcomes

Test 1 Single injection well test, 11 kt-CO2 CO2 injectivity confirmed; CO2 wellbore injected from May 2004 to January phase behavior and reservoir response confirmed to be within the range of model 2005 predictions Test 2 EGR test, two producing gas wells Evaluate EGR potential and economics using plus one CO2 well, injecting perfluorocarbon tracer injection and simulation studies to monitor reservoir 23 kt-CO2 from February 2005 displacement process; no clear to August 2006 demonstration of enhanced recovery

The final phase of the project provides for injection ramp up to 480 kt-CO2/year, limited by the capacity of the amine stripping plant, with a total of 8 Mt-CO2 potentially to be injected over a 20-year project life.

Planned EGR demonstration project—Hewett field, North Sea, UK sector The Hewett gas field, discovered in 1966 and located in the UK sector of the southern North Sea, is a candidate EGR storage site that was one component of the RWE npower, Peel Energy entry to the UK CCS Commercialization competition. The project was based on CO2 capture from a 1.6 GW (2 3 800 MW) supercritical coal-fired power plant that was planned to be built by RWE npower at Tilbury in Essex, UK, with storage in the depleted Hewett gas field. The field, previously operated by Tullow Oil plc (now by ENI), contained an estimated 98 Gm3 of gas initial in place, and came into production in 1973 from two high permeability sandstone reservoirs (the Upper and Lower Bunter Sands) at depths of 800 to 1250 m. The two Bunter sands in the Hewett field are considered to be an ideal storage site in view of their depth, size, and high permeability and are estimated to have a combined storage capacity of over 0.35 Gt-CO2, sufficient to store 30 years of captured CO2 from the Tilbury plant. An unusual aspect of the proposed project was that marine transport of CO2 from Tilbury to the field location was considered, alongside pipeline transport. The project is currently (2017) on hold, following the November 2015 cancellation of the UK CCS Commercialization competition.

Unconventional CO2-EGR storage options Similar to the option for CO2 storage in tight oil formations, the possibility of storing CO2 in shale gas formations has also been investigated (see Brown et al., 2016).

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High water consumption is one of the key sustainability issues for shale gas exploitation, and the possibility of using scCO2 as a fracking fluid, while enhancing gas recovery through the competitive adsorption of CO2 versus CH3, makes this a potentially attractive storage option.

18.4

Storage in depleted gas fields

Even without the benefit of increased recovery, gas fields that have reached the end of their producing life, having the benefit of detailed subsurface characterization and a proven caprock, are also ideal candidates for geological storage. Examples of this approach include the Lacq CCS Pilot operated by Total, and the Scottish and Southern Energy (SSE)/Shell Peterhead-Goldeneye project.

Lacq-Rouse CCS demonstration pilot—Rousse field At the Lacq CCS demonstration pilot, operated by Total, CO2-rich combustion gases from a 30 MWth oxy-fueled combustion unit were dehydrated, compressed, and transported 30 km for injection at a depth of 4.5 km into the Mano dolomite formation in the depleted Rousse gas field located near Pau, southwest France. The single gas production well, which had been in operation for 30 years, was recompleted for CO2 injection and monitoring in 2009 and injection commenced in 2010. Over the injection period of 39 months, 51 kt-CO2 were injected.

Planned depleted gas field storage project—Goldeneye field, North Sea, UK sector The Shell operated Goldeneye gas-condensate field was discovered in 1996 and produced 16.1 Gm3 (568 Bscf) of gas and 4.1 Mm3 (26 million bbl) of condensate from the Captain Sandstone between 2004 and 2011. The field was the proposed storage site for the Peterhead CCS project, which has also been put on hold following the UK competition cancellation. The project proposed to capture B1 Mt-CO2/year from one of the three 385 MW combined cycle gas turbines at the Peterhead Power Station in Aberdeenshire, Scotland, to be transported via the existing 102 km gascondensate production pipeline and injected, using the existing platform and wells (refitted for CO2 service), into the depleted gas reservoir at a depth of B2.5 km. Some 10 Mt-CO2 was planned to be stored over a 10-year period, starting around 2020, with the site planned to be certified for a total storage capacity of 20 Mt-CO2.

18.5

Enhanced coal bed methane recovery

Coal is an effective sorbent for methane, CO2, and other gases, and coal bed methane (CBM) is economically exploited from unmineable coal beds in a number of areas including the United States, Canada, and Australia. CBM is released from

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coal by reducing the pore pressure within the coal bed—a variant of pressure swing desorption (see Chapter 7). This is achieved by drilling wells into the bed and pumping off water to reduce the hydrostatic pressure. As the pressure is reduced, liberated methane is transported to the well through the system of fractures, or cleats, in the coal bed. The key requirements for CBM recovery are as follows: G

G

High initial methane content, which increases with pressure and depth, and can be up to 20 25 m3/t Adequate permeability for gas flow from a well-developed, open cleat system, which typically decreases with increasing depth due to cleat closure under the increasing confining stress.

These opposing requirements dictate a depth range of between B300 and B1000 m for economic CBM exploitation. Injection of CO2 into coal beds can result in ECBM recovery as a result of the competitive adsorption between these two gases (see Section 7.1). Due to its higher heat of adsorption, CO2 will be preferentially adsorbed onto the coal surface. This is illustrated in Figure 18.5, which shows the Langmuir isotherms for methane and CO2. Preferential adsorption of CO2 results in the desorption of methane, typically two molecules of CO2 being adsorbed for each desorbed molecule of CH4, which is then able to flow through the cleat system to a producing well. Although this process has been demonstrated in a number of pilot-scale trials, it suffers from a number of technical and economic challenges, notably: G

Reduction of coal permeability due to swelling of the coal matrix on CO2 adsorption, potentially leading to an increase in the number of injection wells required. In some pilot tests this loss of permeability has been partially overcome by increasing injection pressure to maintain the rate of CO2 injection.

20

Adsorption (m3/t)

16 CO2 12 CH4 8 N2 4 0.0 0

2.0

4.0

6.0

8.0

10.0

Pressure (MPa)

Figure 18.5 Langmuir isotherms for CO2 and methane adsorption onto coal.

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G

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Carbon Capture and Storage

Permeability reduction as a result of coal softening, which occurs when the adsorption of CO2 reduces the glass transition temperature (see Glossary) to below the formation temperature, causing an in situ transition from a glassy phase to a soft plastic phase. Low ratio of incremental methane recovery to CO2 injected volume. Pilot results have yielded incremental methane recoveries between 15% and 50% of the injected CO2 volume.

Active ECBM pilot project—PCOR, North Dakota, USA Characterization studies conducted by the Plains CO2 Reduction Partnership (PCOR) have shown that low-rank coal seams in North Dakota have the capacity to store up to 8 Gt-CO2 and suggested that over 500 Gm3 of methane could be produced from these seams. The studies have been followed by a field validation test, commenced in 2007 with the construction of a five-spot test pattern, with one injection well surrounded by four monitoring wells. Injection of a planned 400 t-CO2 into a 3 m thick lignite seam at 330 m depth started in March 2009. The project is the first field trial conducted to test the ability of lignite coal seams to store CO2. In view of the high volumetric CO2 requirement, further development of ECBM beyond the pilot stage is likely to require the availability of zero or negative cost CO2 that will follow the introduction of financial incentives for carbon sequestration.

18.6

Geological storage and geothermal energy

A number of approaches have been proposed to integrate subsurface CO2 storage with geothermal energy extraction, including the simple use of CO2 as a working fluid in a conventional circulating geothermal system and the extraction of heat from an extended plume of injected CO2.

18.6.1 CO2 use in engineered geothermal systems The use of CO2 instead of water as the working fluid in engineered geothermal systems (EGS) was proposed as early as 2000 (see Brown, 2000) as a means of achieving a degree of carbon storage while delivering geothermal energy to replace fossil fuel combustion. The main advantage of using CO2 as the working fluid arises from the so-called thermosiphon effect, which arises from the density difference between hot and cold scCO2. The hydrostatic head in a hot production well will be less than in a cold injection well, increasing the pressure difference between injection and production wells; aided by the lower viscosity of scCO2 compared to water, this leads to a higher flow rate and increased heat extraction. Alternatively, the thermosiphon effect can be used to reduce the pumping power required to circulate the working fluid. Further advantages can arise under specific

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conditions due to the lower geochemical reactivity of CO2 compared to hot or supercritical water. In addition to the circulating working fluid volume, amounting to some 500 kt-CO2 for a 100 MWe CO2-EGS plant, additional CO2 would also be stored as a result of loss of the working fluid by diffusion into the surrounding rock. This could amount to 3 Mt-CO2/year for a 100 MWe CO2-EGS plant, roughly equivalent to the CO2 emission from a 300 MWe coal-fired plant.

18.6.2 CO2 plume geothermal energy The potential to extract geothermal energy from the injected CO2 plume at a geological storage site, known as CPG, was first proposed by Randolph and Saar in 2010 as a way to improve the economics of geological carbon storage. The concept, illustrated in Figure 18.6, involves the back-production of hot scCO2 from a suitable offset location, extraction of heat, and reinjection of the cooled scCO2. Extracted heat could be put to a variety of uses including space heating and power generation. The CPG concept has also been included in a number of more complex proposals to use subsurface porous media for energy storage. One such system, illustrated in Figure 18.7 (section across a circular configuration), combines CO2 storage with a multi-fluid geothermal system including both CO2 and brine as working fluids. The CO2 injection (at A in the figure) and CPG element of this scheme is located at the center of the concentric configuration. Cold brine injection (at B) and hot brine production (D) create a hydraulic barrier constraining movement of the CO2 plume, while geothermal energy is extracted from hot scCO2 production (C) and hot brine production (D and E). This configuration has also been proposed as a method of storing thermal energy, by injected hot rather than cold brine at location B, with heat provided by nuclear or concentrated solar power plant production in excess of demand. Electrical power Turbine Heat exchanger

scCO2

Space heating

Produced hot scCO2

Overburden Injected cold scCO2

Aquifer

Figure 18.6 Schematic configuration for CPG system.

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Geothermal power plant

scCO2 supply

Overburden Cold scCO2

Aquifer

Hot scCO2

Cold scCO2

C scCO2 cushion Hot brine

A

Hot brine D

Hydraulic barrier

Cold brine

Hydraulic barrier

Hot brine

Cold brine

Hot brine E

B

Geothermal heat source

Figure 18.7 Integrated CO2 storage and multi-fluid geothermal system. Source: After Buscheck et al. (2014).

18.7

Compressed air energy storage

CAES is an approach to storing electrical energy produced at times of excess supply and making it available again at times of high-demand. In a CAES system, electrical energy is used to compress air which is stored in sealed underground caverns and back-produced when required with energy recovered in a gas turbine. Two commercial CAES systems are currently in operation worldwide—in the United States and Germany. At the largest of these, in operation since 1978 at Huntorf in Germany, a 0.3 3 106 m3 cavern is pressurized using 60 MW of excess nuclear generated electricity for 8 h per daily cycle and the compressed air feeds a natural gasfired turbine to generate 320 MW for 2 h during the high-demand period. CAES has also been proposed using porous media, such as aquifers or depleted gas fields, for air storage instead of caverns, and this variant, known as porous media compressed air storage (PM-CAES), has been the subject of an R&D project funded by Pacific Gas & Electric in the United States since 2010. Environmental permitting for a pilot phase covering compression, injection, and withdrawal testing was concluded in 2014 and, building on the results of this test, successful completion of the current plan would see a 300 MW plant in operation after 2020. A large proportion of the gas injected in a CAES system is not back-produced during each production period, and forms a cushion, the main function of which is to provide compressibility in the system to accommodate the working gas injected in each daily or weekly storage/delivery cycle. The use of CO2 as a cushion gas in PM-CAES systems has been proposed as a way of combining carbon storage with energy storage. This would involve the injection of a volume of CO2 as cushion gas prior to the start-up of a PM-CAES facility. While such a system would not provide

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an ongoing carbon storage capability, the pre-stored volume (potentially several Mt-CO2) could generate significant revenues from carbon credits that would contribute to the economics of the CAES system.

18.8

References and resources

18.8.1 References Bachu, S., 2007. Carbon dioxide storage capacity in uneconomic coal beds in Alberta, Canada: methodology, potential and site identification. Int. J. Greenhouse Gas Control. 1, 374 385. Benson, S., 2005. Overview of geological storage of CO2. Carbon Dioxide Capture for Storage in Deep Geological Formations. 2, 665 672. Brown, D.W., 2000. A hot dry rock geothermal energy concept utilizing supercritical CO2 instead of water. Proceedings of the Twenty-Fifth Workshop on Geothermal Reservoir Engineering. Stanford University, Stanford, CA, January 24 26, 2000 (SGP-TR-165). Brown, S., Gadikota, G., Mac Dowell, N., 2016. Modelling the adsorption-desorption behaviour of CO2 in shales for permanent storage of CO2 and enhanced hydrocarbon extraction. Energy Procedia. 114, 6942 6949. Buscheck, T.A., et al., 2014. Integrating CO2 storage with geothermal resources for dispatchable renewable electricity. Energy Procedia. 63, 7619 7630. Burton-Kelly, M.E., Dotzenrod, N.W., Feole, I.K., Peck, W.D., Ayash, S.C., 2016. High level screening for Williston Basin residual oil zones using location-independent data. Energy Procedia. 114, 3518 3527. IEAGHG, 2007. Storing CO2 underground. IEA Greenhouse Gas R&D Programme 2007. Available at http://www.co2net.eu/public/reports/storingCO2%20sml.pdf. Kuuskraa, V.A., Petrusak, R., Wallace, M., 2017. Residual oil xone “fairways” and discovered oil resources: expanding the options for carbon negative storage of CO2. Energy Procedia. 114, 5438 5450. Lindeberg, E., Grimstad, A.-A., Bergmo, P., Holt, T., Wessel-Berg, D., Torsæter, M., 2017. Large scale tertiary CO2 EOR in mature water flooded Norwegian oil fields. Energy Procedia. 114, 7096 7106. Marchetti, C., 1977. Geoengineering and the CO2 problem. Clim. Change. 1, 59 68. Oldenburg, C.M., L. Pan, 2014. Utilization of CO2 as cushion gas for porous media compressed air energy storage. Lawrence Berkeley National Laboratory paper LBNL-6375E. Preston, C., et al., 2005. IEAGHG Weyburn CO2 monitoring and storage project. Fuel Process. Technol. 86, 1547 1568. Randolph, J.B., Saar, M.O., 2011. Coupling carbon dioxide sequestration with geothermal energy capture in naturally permeable, porous geologic formations: implications for CO2 sequestration. Energy Procedia. 4, 2206 2213. Sorensen, J.A., Kurz, B.A., Hawthorne, S.B., Jin, L., Smith, S.A., Azenkeng, A., 2017. Laboratory characterization and modeling to examine CO2 storage and enhanced oil recovery in an unconventional tight oil formation. Energy Procedia. 114, 5460 5478. Spence, B., Horan, D., Tucker, O., 2014. The Peterhead-Goldeneye gas post-combustion CCS project. Energy Procedia. 63, 6258 6266. StatoilHydro, 2003. Best Practice Manual from SACS—Saline Aquifer CO2 Storage Project. Available at www.co2store.org, SACS project page.

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van der Meer, B., 2005. Carbon dioxide storage in natural gas reservoirs. Oil Gas Sci. Technol.—Revue de l’Institut Franc¸ais du Pe´trole. 60 (527 536). Available at http:// ogst.ifp.fr. Wilson, E.J., Johnson, T.L., Keith, D.W., 2003. Regulating the ultimate sink: managing the risks of geologic CO2 storage. Environ. Sci. Technol. 37, 3476 3483. US DOE NETL, 2008. Methodology for Development of Geological Storage Estimates for Carbon Dioxide. Available at www.netl.doe.gov/technologies/carbon_seq/refshelf/ methodology2008.pdf.

18.8.2 Resources CAES project developers: Apex-CAES, www.apexcaes.com; Ridge Energy Storage, www. ridgeenergystorage.com; Storelectric, storelectric.com. CO2DeepStore (sequestration in depleted gas fields): www.co2deepstore.com. DNV (developing standards to qualify sequestration sites): www.dnv.com/industry/energy/ segments/carbon_capture_storage. EnCana Corporation (operator of the Weyburn EOR project): www.encana.com. Energy Storage Sense (information web site on energy storage technologies): http://energystoragesense.com/compressed-air-energy-storage/. Gaz de France (K12-B injection project web site): www.k12-b.nl. Global CCS Institute (CCS project database): www.globalccsinstitute.com/projects/largescale-ccs-projects. IEAGHG (interactive tool for design of monitoring programmes for geological storage): www.co2captureandstorage.info/co2tool_v2.1beta/index.php. Pacific Gas and Electric (developing world’s first PM-CAES system): www.pge.com/en_US/ about-pge/environment/what-we-are-doing/compressed-air-energy-storage/compressedair-energy-storage.page. Total S.A. (Lacq CCS pilot. Project and injection period 2006 2013): www.globalccsinstitute. com/publications/carbon-capture-and-storage-lacq-pilot-project-and-injection-period-20062013. UK Department for Business, Energy & Industrial Strategy (formerly Department for Energy and Climate Change (DECC)) (knowledge sharing site for UK CCS Commercialization competition): www.gov.uk/government/collections/carbon-capture-and-storage-knowledgesharing. US DOE (2008 Carbon Sequestration Atlas II; documents over 3500 Gt-CO2 storage potential in oil and gas reservoirs, coal seams, and saline formations in the USA and Canada): www.netl.doe.gov/technologies/carbon_seq/refshelf/atlasII.

Storage monitoring and verification technologies

19

This chapter introduces the wide range of technologies available to monitoring storage performance, including a number of application examples. In many cases these technologies will also play an important role in the initial characterization of a storage complex, during the project design stage, and data acquisition to provide the baseline for operational monitoring will often take place during site assessment. A high-level overview and brief description of the main groups of monitoring and verification techniques is given in Table 19.1.

19.1

Seismic surveying

Seismic surveying is the main technology used to generate high-resolution 3D images of the subsurface. Reflection seismology was developed in the 1920s as a tool for oil exploration and relies on the reflection or refraction of acoustic energy from interfaces between formations with differing acoustic impedances. In conducting a land-based survey, an array of acoustic sensors known as geophones is first arranged in a series of parallel lines on the surface. A pulse of seismic energy with a well-defined wave characteristic is emitted by the dropping or vibration of a large weight, or occasionally still by detonating an explosive charge, and the acoustic energy travels down into the earth. The acoustic impedance (Z) of a rock layer (a) is given by: Z a 5 va ρ a

(19.1)

where v is the acoustic velocity (m/s) and ρ is the rock density (kg/m3) of the layer. As the wave passes from layer a to layer b, with impedance Zb, a fraction of the incident energy is reflected. For normal incidence, this reflection coefficient is given by: R 5 ðZb 2 Za Þ=ðZb 1 Za Þ

(19.2)

The reflected energy is detected by the geophone when it reaches the surface after a two-way travel time: t 5 2D=V

(19.3)

where D is the depth below surface of the reflecting layer and V is the average acoustic velocity of rock down to that depth. The received energy at each geophone Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00019-2 © 2017 Elsevier Inc. All rights reserved.

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Table 19.1 Monitoring techniques for geological storage Characterization or monitoring technique

Description

Plume location and movement Time-lapse seismic

Vertical seismic profiling

Cross-well seismic

Microseismic

Electrical resistance tomography (ERT)

Cross-well resistivity

Gravity surveys

Tracer injection

Typically acquired on a 3D grid, but also possible on 2D lines. May also be acquired using permanently installed geophones, particularly offshore Seismic survey from a surface source to geophones located in a well, generating a one-way vertical profile that can be used to calibrate 3D data and provide near-well imaging of reservoir properties and CO2 movement Seismic survey with both source and geophones located in boreholes. Generates both reflection profiles and velocity tomography that can be used to calibrate 3D data and in timelapse mode to image changes in reflectivity and velocity between wells Measurement of microseismic signal generated by fracturing events as a result of injection, using either surface or downhole mounted geophones ERT images the subsurface resistivity with measurements between ground based or borehole mounted electrodes; long electrode ERT uses the casing of a well as an electrode to extend this technique to greater depth A variant of ERT using electrodes mounted or moving in two wells, and providing a 2D profile of the resistivity distribution between the wells Measurement of the local gravitational field using surface or airborne gravimetry, providing a low-resolution map of changes in pore fluid density due to plume movement Marker chemicals coinjected with CO2 and detectable at very low concentrations to enable early breakthrough detection

Surface deformation monitoring (SDM) InSAR and DInSAR

Tiltmeters

Techniques for processing satellite-based radar images to detect surface deformation down to millimeter scale over timescales of months to years Shallow borehole mounted (,10 m) sensors that can detect microradian scale geomechanical deformation, equivalent to 1 mm deflection over a 1 km range

CO2 leak detection LIDAR

Laser monitoring techniques that can detect the location and movement of CO2 in the atmosphere with ppb sensitivity (Continued)

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Table 19.1 (Continued) Characterization or monitoring technique

Description

Hyperspectral remote sensing

Imaging spectroscopy uses spaceborne sensors to collect a spectrum at each image point, rather than an amplitude at a single wavelength. Can be applied to detect atmospheric gases and surface minerals, and to characterize ecological habitats Detection of gases such as CO2 and methane as a result of the attenuation of an infrared beam transmitted between a source and detector A technique for determining the vertical flux of a gas species such as CO2 by statistical analysis of the vertical velocity and fluctuating concentration of turbulent eddies Collection and analysis of gas samples from the soil or shallow boreholes. Isotopic or tracer analysis can distinguish leakage of injected from biosphere-generated CO2 Collection and analysis of fluid samples from drinking water wells, and any monitoring wells located above the storage complex, to detect elevated CO2 concentration

Open-path laser gas detection Eddy covariance measurement Soil gas sampling

Fluid sampling

Injection well monitoring Injection well pressure and Standard measurement of well pressures, volumes, and temperature temperatures; used as input to dynamic reservoir modeling and to identify injection well problems

Geochemical characterization Injection-production experiments

Injection of a limited volume of scCO2 into a host formation, followed by a soaking period (weeks to months) and a period of back-production and sampling to assess the geochemical and other consequences of CO2 injection

Microbiological monitoring Fluid sampling and microbial analysis

Collection and analysis (geochemical and biological) of fluid samples from monitoring wells located in the host formation, to characterize microbial communities and activity following CO2 injection

is then recorded for a period of several seconds after each “shot” of the seismic source, and several shots are made at each location to improve the signal-to-noise ratio of the acquired data. The geophone array is moved to the next location and the process is repeated. For 3D surveying, geophones are typically located on an

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xy grid at a spacing of 12.5 or 25 m over an area that may cover thousands of square kilometers. Depending on the type of source used, the energy pulse emitted by the seismic source will typically contain both compressional and shear wave energy. Compressional waves, or P-waves, are characterized by vibrations that are parallel to the direction of propagation, while for shear waves (S-waves) the vibration is perpendicular to the wave propagation. P and S stand for primary and secondary, reflecting the fact that velocities are higher for P- than for S-waves, and therefore P-waves are the first to arrive at a detector. Geophones can be designed to detect either P- or S-waves, or both, although most seismic surveys are recorded using P-waves only. The received energy at each geophone is then recorded for a period of several seconds after each “shot” of the seismic source, and several shots are made at each location to improve the signal-to-noise ratio of the acquired data. The geophone array is moved to the next location and the process is repeated. For 3D surveying, geophones are typically located on an xy grid at a spacing of 12.5 or 25 m that is progressively moved over an area that may cover many hundreds of square kilometers. The acquisition process is similar although logistically simpler offshore, with arrays or streamers of hydrophones pulled along by one or more vessels while an air gun is used to generate the source pulse. GPS positioning of the geophones at each shot point is critical to accurately locate identified subsurface features, and strong currents or poor surface weather conditions can therefore disrupt the offshore acquisition process. S-waves cannot be recorded for offshore seismic surveys, unless the geophones are located on the seabed, because shear waves cannot travel through water. Geophone or hydrophone arrays may also be permanently installed over the area of interest to simplify the acquisition of repeated (time-lapse) surveys. While this reduces the incremental cost of subsequent surveys, it represents a significant upfront capital investment which requires careful economic evaluation. One such example is the permanent array comprising 7 geophones and 17 hydrophones that was installed at the Ketzin storage pilot site near Berlin, Germany. The sensors were installed at 13 locations along a single 120 m long receiver line, with hydrophones installed in shallow wells at depths up to 50 m. Despite the limited areal distribution of the sensors in this instance, coverage of the subsurface area of interest was achieved by operating the dropped weight seismic source at locations offset by 200 m or more from the receiver line. Following the raw geophone data acquisition, multiple geophone records or “traces” are “stacked” to improve signal-to-noise. Deconvolution using the waveform of the source pulse (known as the “wavelet”) reveals the impedance contrasts causing reflection, and “migration” of these events in 3D adjusts for the source to geophone geometry to correctly locate events in the subsurface space. High-resolution 3D seismic can reveal features on a 2025 m scale at depths of several kilometers, including the internal structure of sedimentary bodies, and can also indicate the fluid fill and pressure in a formation as a result of the impact of

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these parameters on impedance. Acquisition and processing parameters can be adjusted to achieve the best resolution for a particular target depth, so that surveys acquired to evaluate deep formation may need to be reacquired or reprocessed to achieve optimal results for targets such as shallower aquifers.

19.1.1 Time-lapse seismic monitoring Time-lapse (or 4D) seismic is the most important technique developed to date for monitoring an injected CO2 plume, and its effectiveness has been well established in a number of cases, notably in the Sleipner project described below. This technique relies on the acoustic impedance contrast between rock containing different fluids (water, supercritical CO2, or hydrocarbons), and the comparison of successive surveys indicates areas in the subsurface where one fluid has replaced another or where significant pressure changes have occurred. The time-lapse difference signal between successive surveys will be strongest for formations with high porosity and compressibility, since this increases the degree to which pore fluids affect the seismic signal, while low porosity and compressibility will reduce the influence of pore fluids and these formations will therefore be less favorable candidates for time-lapse seismic monitoring. This dependence can be easily observed from the two governing equations for the dependence of velocity on bulk modulus, and the dependence of bulk modulus on porosity and fluid fill. The P-wave velocity is given by: 1

VP 5 ½ðK 14μ=3Þ=ρ / 2

(19.4)

where K and μ are the bulk and shear moduli of the formation and ρ is the formation density. The bulk modulus of a fluid-saturated rock is given by the Gassmann equation: Ksat 5 Kf 1 ð1  Kf =Km Þ2 ðΦ=Kfl 1ð12ΦÞ=Km  Kf =Km2 Þ21

(19.5)

where the bulk modulus subscripts sat, f, m, and fl refer to the saturated formation, the dry rock frame, the mineral matrix, and the pore fluid, respectively, and Φ is the porosity. Since pore fluids do not transmit shear stress, μ is independent of the pore fluid. Recalling that bulk modulus is the inverse of compressibility, it is apparent from Equation (19.5) that, if the compressibility of the formation is low, that is if Kf  Km, then Ksat  Kf and there is no effect of fluid on VP. If the formation compressibility is high, however (Kf{Km), Equation (19.5) reduces to: Ksat 5 Kf 1 1=ðΦ=Kfl 1 ð1 2 ΦÞ=Km Þ

(19.6)

in which case it is clear that the effect of Kfl on Ksat, and consequently on VP, is increased as porosity increases.

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The high porosity unconsolidated Utsira sandstone at the Sleipner field is therefore an ideal candidate for monitoring using time-lapse seismic, and the repeated monitoring surveys acquired over the CO2 plume provide a text book example of the technique (see case study below). The Sleipner results demonstrated the central role of time-lapse seismic in monitoring geological storage operations, as well as the potential for plume dynamics to be significantly affected by small-scale geological heterogeneities which are well below seismic resolution and are unlikely to be adequately represented in an initial geological model. The potential for 4D seismic to improve geological understanding and potentially impact on storage operations by revealing geological heterogeneity and the impact on connectivity has also been demonstrated in a CO2-EOR setting (see Burnison et al., 2017). As well as imaging plume movement within the storage complex, time-lapse seismic will also be able to detect gas migration paths in the overburden, particularly if CO2 migrates above the depth limit for supercritical conditions.

19.1.2 Amplitude versus offset analysis Amplitude versus offset (AVO) analysis, in which the amplitudes of seismic reflection signals are compared for different reflection angles, is a widely applied technique in the oil and gas industry to identify hydrocarbon bearing, and particularly gas bearing, reservoirs. Figure 19.1 illustrates the AVO concept. For a soft reflector, such as a gas bearing sand contained within harder shales, the amplitude of the reflection signal increases as the offset between the source and receiver, and therefore the incidence angle θ, increases. This occurs because the compressional (P) and shear (S) wave velocities and reflectivities respond differently to the presence of gas, and the S-wave response has an increasing impact as the incidence angle increases. An analysis of reflection AVO therefore gives an indication—by no means infallible—of the type of fluid present in a reservoir. AVO analysis is complicated for thin layers as a result of the interference of multiple reflections between the upper and lower boundaries. However, at the Sleipner field, a novel AVO processing technique has been developed in an effort to determine Seismic source

Surface

Seismic receiver

Offset

+R

600 Incident ray path (P-wave)

+ Gradient sin2θ

Reflected ray path

a a

650 Time

– Gradient –R

Geological interface Reflection

Small time window from gathered geophone traces

Reflectance peak/trough amplitude vs sin2θ

Figure 19.1 Seismic reflection amplitude variation versus offset for a soft reflector.

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the thickness of the CO2 layers accumulating below thin intra-formational shales. AVO analysis has also been reported at the Ketzin Pilot project.

19.1.3 Vertical seismic profiling VSP is a seismic surveying technique in which the receiving geophones are located in a borehole—either permanently installed or run into the well on a wireline— rather than being arrayed on the surface. The VSP source remains on the surface and alternative source locations define a number of variations on the VSP theme, as summarized in Table 19.2. Receiver location—fixed or moving—is common to all types of VSP survey and a typical spacing between installed geophones or survey depths is in the order of 550 m. These VSP survey layouts are illustrated schematically in Figure 19.2. The receiving geophones are located above the zone of interest, and record the upgoing wave after reflection from impedance contrasts in the zone of interest. The downgoing wave from the source is also recorded and is used in the processing flow. In common with normal seismic surveying, each source to receiver signal is recorded many times (known as multiple fold, e.g., 12-fold) and the traces are averaged to improve the signal-to-noise ratio. VSP results typically show a higher signal to noise and improved resolution when compared to seismic data acquired from surface surveys.

Table 19.2 Alternative VSP acquisition configurations VSP variant

Description

Zero-offset VSP

A fixed source is located adjacent to the monitoring wellhead and data is acquired between the fixed shot location and several receiver locations. Multiple receiver locations are achieved by having several fixed geophones in the monitoring well or by running one or more geophones into the well on an electric wireline and positioning them at the desired survey depths A fixed source is located at an offset distance from the monitoring well. Typically multiple offset locations will be used for the source with locations determined by the specific site geometry, e.g., aligned to the orientation of a horizontal injection well, or on the line joining an injection well and a monitoring well. Offset distance is determined by the depth of the zone of interest Shots are taken from a number of locations arranged along a line (the walkaway line) which runs through, or very close to, the wellhead of the monitoring well. Total walkaway length will be determined by the depth of the zone of interest, with typical shot spacing being in the order of 2550 m

Offset VSP

Walkaway VSP

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Monitoring well

Injection well Walkaway VSP shot locations

Zero-offset VSP Offset VSP shot locations shot location

Figure 19.2 Schematic shot locations for zero-offset, offset, and walkaway VSP surveys. S

Difference 2009–2008

Offset 795–705–615–525–435–345–255–165–75

N

15 105 195 285 375 465 555 645 735

Time (s)

0.5

1.0

Figure 19.3 Time-lapse walkaway VSP survey: 2008 baseline2009 monitor difference. Source: From Cheng et al. (2010).

Repeated VSP surveys can also be interpreted for time-lapse effects, with a baseline survey recorded before the start of injection, followed by repeat surveys that are used to calculate a time series of difference images. Time-lapse VSP analysis has been used on a number of EOR CO2 floods, including the Weyburn and SACROC fields. Figure 19.3 illustrates a VSP difference image acquired on the SACROC field in West Texas, where an EOR CO2 flood has been in progress since 1972. The walkway surveys were acquired in 2008 and 2009 and clearly indicate the effect of injected CO2, successfully demonstrating the applicability of timelapse VSP to geological storage monitoring.

19.1.4 Cross-well seismic Cross-well seismic is a derivative of VSP in which both the source and the receivers are located within boreholes. This configuration can be used either in reflection

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0

P-Wave offset (m)

497

30

0

S-Wave offset (m)

30

1475

Depth (m)

Depth (m)

1500

1530

1560 Injection zone

Injection zone

1600 –1.0 –0.5 0.0 0.5 1.0

–0.2 –0.1 0.0 0.1 0.2

Change in velocity (KM/S)

Change in velocity (KM/S)

Figure 19.4 Cross-well P- and S-wave velocity tomography. Source: From Daley et al. (2008), with permission.

mode, generating cross-well images similar to VSP results, or in tomographic mode, in which sourcereceiver travel time is used to build up an image of the velocity distribution between the two wells. Time-lapse cross-well seismic can therefore image both velocity and reflectivity changes. Acquisition of both compressional (P-wave) and shear (S-wave) data allows elastic properties such as Poisson’s ratio and shear modulus to be estimated. Figure 19.4 shows a cross-well tomographic image from the Frio formation in Texas. P- and S-wave arrivals were recorded between injection and observation wells separated by 30 m. Baseline and monitor surveys were recorded either side of a 10-day injection test in which 1600 t-CO2 were injected into the 4.6 m thick Upper C-sand at a depth of B1530 m, as indicated in the figure. The minor S-wave velocity difference close to the injection zone is indicative of a localized change in shear modulus due to injection, while the larger and more areally extensive P-wave velocity difference, due to substitution of brine in the pore space by CO2, delineates the injected CO2 plume.

19.1.5 Passive seismic monitoring Passive seismic, induced seismicity or microseismic, monitoring refers to the detection of small-scale rock failure events, predominantly on pre-existing fractures or small faults, occurring as a result of pore pressure and effective stress changes from fluid injection or withdrawal. Microseismic events are detected by geophones located either in deep boreholes close to the injection formation or in near-surface arrays using shallow boreholes, the trade-off being largely one of cost versus sensitivity. Time-of-flight evaluation at multiple, spatially separated detection points allows the region of geomechanical deformation causing these events to be delineated. The

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spatial resolution that can be achieved in locating microseismic events depends on the extent of the sensor arrays, a resolution in the order of 10 m being achievable with multiwell, extended arrays. Passive seismic monitoring has the advantage of very low costs for ongoing operation and maintenance, which makes it viable for long-term or very long-term monitoring. Depending on the presence of existing regional seismic monitoring networks, installation as early as the site assessment stage may be beneficial in order to generate a sufficiently long baseline recording of the spectrum of natural seismic events before the start of injection. This technique has been demonstrated in the IEA GHG Weyburn EOR/Storage project. An array of eight geophones was positioned between 100 and 300 m above the top of the Midale host formation, and permanently cemented into a monitoring well located 50 m from an injection well. Figure 19.5 shows the areal location of the wells and of the approximately 100 located events detected during a monitoring period from August 2003 to January 2006, which are mostly located in clusters around certain faults and production wells (see Verdon et al., 2010). The application at Weyburn demonstrated the value of passive seismic as a lowcost technique to monitor geomechanical deformation. In the particular case of Weyburn, the results revealed a low rate of induced microseismic events, predominantly clustering in periods of high injection rate, which indicated that injection was not causing significant deformation, and provided a degree of assurance with regard to containment risks.

N

Fault Injector well (121/06-08) Monitoring array

Production wells

Microseismic events 500 m

Figure 19.5 Weyburn passive seismic configuration and event locations. Source: After Verdon et al. (2010).

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499

Gravity and electromagnetic surveys

Other surface geophysical monitoring techniques that have been applied to storage monitoring include microgravity and electromagnetic surveys. These measurements are unable to match the resolution of 4D seismic, but may have a role to play in longer term monitoring programs, e.g., after the cessation of injection at a storage site, as a trigger for more extensive and expensive monitoring if anomalous behavior is identified.

19.2.1 Microgravity surveying Surface or seabed measurements of microgravity can be used to map subsurface density changes resulting from CO2 injection, while measurements taken in boreholes can also determine the vertical gradient of gravitational acceleration (dGz/dz), to identify the vertical position of the density anomaly. Microgravity monitoring has been applied at the Sleipner field, where a baseline survey was acquired in 2002 after some 5 Mt-CO2 had been injected. The survey was acquired by placing a gravimeter onto pre-positioned concrete benchmarks using a remotely operated vehicle (ROV). Thirty blocks were installed at reference locations along two perpendicular lines (3 km NS and 7 km EW) spanning the footprint of the plume. Figure 19.6 shows the seabed gravimeter and the ROV being recovered with gravimeter attached. Modeling studies indicated that the injection of an additional 2 Mt-CO2 would result in a signal of between 28 and 233 μGal, while leakage of CO2 to shallower levels, and lower densities, could give a signal in excess of 2100 μGal. An initial time-lapse dataset was acquired in 2005, and the data were corrected for the impact of production from the Sleipner gas reservoir as well as settling of the concrete benchmarks into the seabed due to sediment scouring. With the plume geometry constrained by the 4D seismic results it was then possible to estimate

Figure 19.6 Seabed gravimeter and ROV during 2002 baseline survey at Sleipner. Source: From Chadwick et al. (2006), with permission.

500

Carbon Capture and Storage

0 –10

Peak Δg (μGal)

–20 –30 –40 –50 –60 –70 –80 200

300

400

500

CO2 density

600

700

800

(kg/m3)

Figure 19.7 Computed seabed gravity anomaly at Sleipner as a function of CO2 density. Source: After Chadwick et al. (2006).

a lower bound on the average in situ CO2 density of 640 kg/m3, at a 95% confidence level (see Alnes et al., 2008). The computed dependence on CO2 density of the peak gravity anomaly resulting from the injection of 2.3 Mt-CO2 at Sleipner is illustrated in Figure 19.7. This strong dependence of the gravity anomaly on the CO2 density means that microgravity surveying will be particularly effective to monitor for leakage of injected CO2 to shallow levels, which would result in a drop in the average density over time. A second time-lapse dataset was acquired in 2009, with the number of benchmark points increased to 40 to extend the survey over the full area of the plume as observed in the 2008 seismic survey. The 2009 gravity data confirmed the average density range from the first monitor survey and also allowed an upper limit of 1.8% per year to be placed on the rate of dissolution of CO2 into the formation brine. The analysis of the gravity data from Sleipner highlighted the importance of accurately measuring the initial temperature and pressure, particularly if these initial conditions are close to the CO2 critical point.

19.2.2 Electromagnetic surveying Geophysical surveying techniques that rely on natural variations in the earth’s magnetic and electric fields, known as natural source electromagnetic methods or magnetotellurics, have been in use since the 1950s for hydrocarbon and mineral exploration. More recently, techniques have been developed that employ an active controlled-source electromagnetic method (CSEM) to achieve greater signal-tonoise ratio. Two classes of CSEM techniques have been applied for geological storage monitoring—those methods that use an array of sensors deployed either on

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the surface or on the seabed, and tomographic methods that use surface-to-well or well-to-well current paths.

Surface and subsea CSEMs Sensor array-based CSEM surveys typically use an electric dipole current source, operating at frequencies of between 0.05 and 100 Hz and delivering a power of up to 100 kW (offshore). The configurations for offshore surveying is illustrated in Figure 19.8. For offshore acquisition, an array of sensors is placed on the seabed by an ROV. Receiving sensors include dipoles detectors aligned both parallel and perpendicular to the source dipole, to detect the response of the formation to both the electrical and magnetic fields emitted by the source. The dipole source is then towed, close to the seabed, in a series of linear paths across the receiver array—a survey geometry similar to the acquisition of offshore seismic using fixed ocean bottom geophones nodes. Onshore, a similar receiver configuration is combined with a mobile source which is activated at a number of locations within and around the receiver array. Subsea CSEM was originally developed for use in deepwater hydrocarbon exploration (water depth .ca. 300 m) because at shallower water depth the receiver signal is dominated by so-called air wave, which passes from source to receiver through the water column and air rather than through the sub-seabed formations which are the target of the survey. However, the technology can now be applied in water depths as shallow as 50 m using low frequencies (below 0.05 Hz) and the latest processing techniques. In deepwater subsea surveys the source is towed close to the seabed, while for shallow water applications the source is towed on or close to the sea surface. CSEM has been applied at the Ketzin CO2 injection pilot using electrodes installed at reservoir depth in the CO2 injection and observation wells as a

Sea surface Dipole transmitting source Receivers Sea bed Schematic electromagnetic signal paths Target reservoir layer

Figure 19.8 Schematic CSEM configuration for offshore surveys.

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current bipole (see Girard et al., 2011). A square-wave modulated current was injected at three frequencies (0.125, 0.5, and 4 Hz) and the resulting electrical and magnetic fields were detected at 14 surface stations arranged over two circles of approximately 0.8 and 1.5 km radius. Following a baseline survey in 2008, time-lapse measurements were acquired in 2009 and 2010. The results of the 2009 survey were in line with the expected resistivity change following the start of CO2 injection, while the 2010 results indicated some unexpected redistribution on CO2 between gaseous and aqueous phases and between different areas of the host formation. Integration with other monitoring results and with further CSEM time-lapse surveys was expected to provide further insight into these results. The feasibility of seabed CSEM for storage monitoring under Sleipner conditions has been demonstrated in modeling studies (see Nord et al., 2011). Although the resolution of the techniques could not compete with 3D seismic, the modeled response was able to detect small changes in CO2 saturation in the high saturation range (SCO2 . 70%).

Electrical resistivity tomography Electrical resistivity tomography (ERT) is a geophysical measurement technique that uses electrodes placed in one or more boreholes to investigate the distribution of electrical resistivity in the subsurface. ERT has been developed since the 1980s and has been applied to a range of subsurface imaging problems, including assessing the integrity of engineered barriers for waste containment (see Newmark et al., 2002). The concept is illustrated in Figure 19.9 for simple and advanced electrode configurations. In the simplest configuration, known as a polepole array, a single current electrode is located in one well, while the second well contains a single potential electrode. The return electrodes for both current and potential need to be at an effectively infinite distance from the boreholes, which could mean 10 km or more for two boreholes separated by 500 m. At the other end of the complexity range for electrode configurations, an array of electrodes, insulated from the well casing, is installed into one or more wells surrounding the region to be imaged. Any pair of electrodes can then be used as a bipole for current or potential, including electrode pairs in the same well or in different wells (cross-hole measurements). To provide optimal resolution, the distance between adjacent electrodes should be less than the thickness of the elements to be resolved, while the total length of the electrode arrays should exceed the well separation distance. In the polepole configuration, the single potential measurement provides an indication of the bulk resistivity of the subsurface volume between the boreholes. While this simple measurement provides no spatial resolution, time-lapse measurements could be used as an additional constraint alongside other monitoring results. For multi-electrode arrays, measurements taken using a large number of in-well and cross-well combinations provide a richer dataset, which is interpreted using inversion software to construct a model of the subsurface distribution of resistivity that

Storage monitoring and verification technologies

Bipole–bipole configuration 1st measurement

A M

2nd measurement

Well A M

Dipole–dipole configuration B N

1

503

A B

2

M N

1 B

Dipole–dipole cross configuration M

B

A

N

2

A B

1

2 B

M N

N

M

N 3rd, etc.

A

Current electrodes:

A,B Potential electrodes

M,N

Figure 19.9 Electrode configurations for ERT.

best fits the observations. As with most monitoring methods, a baseline survey is required to establish the background resistivity distribution as the basis for interpreting subsequent surveys. The feasibility of using ERT for CO2 storage monitoring has been demonstrated at the Ketzin CO2 injection pilot, where electrode arrays were installed in the CO2 injection well and two observation wells, as illustrated in Figure 19.10. Potential measurements were made while injecting a modulated direct current signal of up to 3 A, with the setup allowing measurements over a wide variety of bipolebipole and dipoledipole electrode configurations. Typical potential measurements were in the range of 5 3 1025 to 1021 V. Five time-lapse surveys were acquired between August 2008 and April 2010, and inversion modeling results demonstrated that the array could image the resistivity anomaly resulting from CO2 injection.

19.3

Ground surface deformation monitoring

Deformation of the ground surface above a storage site is a result of poroelastic changes in the subsurface, and the results of SDM can be used as an input to the history matching of coupled geomechanical models which relate SDM

504

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–500 KTZI 202

KTZI 201 KTZI 200

Depth (m) –600

Electrodes located vertically within the CO2 injection sand

–700

–800 –50

150 100 0 X (m)

50 0

50 100

Y (m)

-50

Figure 19.10 Schematic configuration of the Ketzin ERT array. Source: After Schmidt-Hattenberger et al. (2011).

measurements back to strain change in the reservoir. A number of techniques are available to measure surface deformation, including high-precision tiltmeters, differential global positioning systems (DGPS), and satellite-borne synthetic aperture radar (SAR). Each of these techniques has advantages and disadvantages, as summarized in Table 19.3. Integration of several techniques, commonly DGPS with InSAR or with tiltmeters, is a common approach to addressing the shortcomings of any single technique. Design of a technically successful and cost-effective SDM monitoring program requires geomechanical modeling at the project design stage to determine the needed resolution and to determine the number, type, and location of sensors and radar reflectors.

19.3.1 Satellite-borne monitoring DInSAR, or differential interferometric synthetic aperture radar, is a spaceborne sensing technique that can detect surface deformation on a millimeter scale over time-lapse periods of months to years. DInSAR combines two satellite radar data processing techniques: interferometric synthetic aperture radar (InSAR) and differential interferometry. Aperture synthesis is a technique that uses the signals from two or more separate antennas to achieve a spatial resolution that is far below the diffraction limit of a single antenna.

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Table 19.3 Comparison of SDM technologies Technology InSAR and derivative techniques

Advantages G

G

G

G

G

Worldwide coverage Very low cost per unit area Wide areal coverage allows identification of deformation outside the expected area Baseline data already available Near real-time monitoring

Disadvantages G

G

G

G

G

DGPS techniques

G

G

G

G

Measures both vertical and lateral displacements to 12 mm accuracy Can be used to correct both InSAR and tiltmeter data Long-term stability Real-time monitoring

G

G

G

High-precision tiltmeter measurements

G

G

G

G

Exceptional precision, in the order of 1 mm/1000 km provides the highest detail in SDM measurement Measurement precision enables early detection of surface deformation Real-time monitoring Only SDM technique that is potentially applicable to subsea geological storage monitoring, although currently unproven

G

G

G

G

Separation of horizontal and vertical components of the line-of-sight deformation Dense vegetation, snow and surface water affects reflection phase measurement Orbital configuration results in lower sensitivity to north/south versus east/west movement Susceptible to uncertainties due to atmospheric turbulence Precision in the order of a few mm to cm Intermittently affected by ionospheric disturbances caused by solar activity Unobstructed sky view is required, and signal delay due to buildings or other obstructions can reduce accuracy Higher hardware cost limits sensor array size and density Poor long-term stability, due to sensor drift in the order of microradians per month Need to be installed in shallow boreholes (B10 m) to achieve nano-radian precision Environmental sensitivity (temperature and vibration/ noise) Exceptional sensitivity requires careful processing to remove extraneous variations

The technique was first proposed in the 1950s as a system to provide guidance for intercontinental ballistic missiles, and (fortunately!) found its first effective application in the late 1960s in the Radio Astronomy Group at Cambridge University. InSAR has been applied in remote earth sensing since the short-lived mission of the SEASAT satellite, launched in 1978. Aperture synthesis for SAR can be achieved either by combining data from two satellites orbiting in close proximity or by combining data gathered at two positions

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by a single satellite. In either case the combined data need to be acquired over a time period that is short enough for the assumption that the reflector is stationary to be valid. InSAR sensitivity can also be improved by installing radar reflectors at specific points of interest. The differential element of DInSAR refers to the combination of multiple temporally-separated synthetic aperture images of the same ground area, using the phase shift in the radar return signal to determine the spatial movement in the reflector (i.e., the ground surface). Worldwide coverage is available from a number of satellite constellations, and the only limitation on applicability of the technology is that the injection site is onshore. Although InSAR measures surface deformation along the single slant direction of the radar beam, it is possible to resolve vertical and horizontal components of the surface deformation using scenes captured from different directions, for example, from right and left looking satellites, or on ascending and descending orbits. At the In Salah storage site in Algeria, DInSAR images have provided quantitative assessment of the ground surface vertical displacement rate around the CO2 injection wells, aiding characterization of a fracture system which has a significant impact on plume behavior. CO2 injection commenced at In Salah in July 2004 and a DInSAR analysis was performed using satellite data acquired up to mid-2008, after 4 years of injection. The SAR scenes of the field area acquired between July 2003 and May 2008 were screened and stacked to reduce phase noise, and the stacked results revealed a surface deformation rate of up to 7 mm/year around the injection wells. Evolution of the surface deformation was also investigated by generating sub-stacks over progressive time periods. Figure 19.11 illustrates the results of the DInSAR analysis

20

Vertical displacement (mm)

KB-503 KB-501 10

KB-502 0

KB-CB

Start of CO2 injection –10 0

500

1000 Number of days

Figure 19.11 DInSAR results at the Krechba field, In Salah. Source: After Onuma and Ohkawa (2009).

1500

2000

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at three injection well locations (KB-501 to 503) and one gas production well location (KB-CB). When used to constrain a coupled reservoirgeomechanical model, the observed deformation was shown to be the surface expression of poroelastic expansion of the injection formation, with some contribution from expansion of an overlying low permeability (10219 m2, 0.1 μD) formation, located below the ultimate caprock (see Rutqvist et al., 2010).

19.3.2 Surface monitoring using tiltmeters High-precision tiltmeters provide an extremely low-cost technique for monitoring ground surface deformation. Using the same principle as a simple spirit level, although typically measuring 1 m in length and 5 cm in diameter, nanoradian accuracy in tilt measurements can be achieved by electronic detection of the change in resistivity due to movement of the gas bubble in a conductive fluid. This accuracy is equivalent to a 0.01 mm uplift over a typical field-scale distance of 10 km. These instruments have been used in a variety of applications since the mid-1990s, including the monitoring of EOR projects such as steam flooding and hydraulic fracturing, with a demonstrated ability to detect the surface deformation due to fractures initiated at a depth of 5000 m and to infer the fracture orientation. Tiltmeters do however suffer from the disadvantage of poor long-term stability, due to thermal drift. A typical deployment uses either a few tiltmeters installed in deep boreholes or a more extensive near-surface array, which may comprise between 10 and 100 sensors in shallow boreholes with a sensor spacing of between 1/3 and 1/10 of the depth of the zone of interest. The interpretability of tiltmeter results can be improved by integrating a number of GPS stations into the tiltmeter array. For example, this can be used to remove long-term drift or to compensate for aliasing effects due to long sensor spacing.

19.3.3 Differential global positioning systems DGPS monitoring can achieve millimeter accuracy by processing the signals from two or more GPS stations, including a reference station in a location that is not expected to experience surface deformation. Multi-sensor processing can largely eliminate typical GPS inaccuracies due to satellite and receiver clock errors, tropospheric and ionospheric delays, tidal effects, and other biases, while residual errors due to baseline uncertainty and multi-path interference can be reduced by additional signal processing techniques such as Kalman filtering. High hardware costs preclude the use of dense sensor arrays, but the real strength of DGPS as a monitoring technique is when integrated with other techniques to provide a stable long-term reference.

508

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Carbon Capture and Storage

Surface, near-surface, and seabed monitoring

Although the primary aim of storage monitoring is to identify anomalies well before any leakage can occur, a variety of techniques are also available to monitor for surface and near-surface leakage. On land, groundwater sampling, soil gas and atmospheric monitoring can be applied, while isotopic or tracer analysis can be used to discriminate injected from background CO2. The health of plants, assessed by monitoring changes in visible and infrared reflectance spectra, can also be used to identify elevated soil CO2 concentration. For storage in sub-seabed formations, sonar monitoring and sub-bottom profiling can be used to detect gas seepage in shallow sediments or in the water column.

19.4.1 Atmospheric monitoring Atmospheric monitoring is an effective technique to detect, locate, and quantify CO2 leakage that is relatively inexpensive to apply continuously over periods of years to decades. Measurements may be point inlet or open path and may be made either using a network of analyzers located downwind of potential leak points, such as injection wells and surface projection of subsurface faults, or by acquiring periodic surveys over the area of interest using mobile detectors. Current point and open-path detectors, based on absorption of an infrared beam, can measure ambient CO2 concentration with a precision of B0.1 ppm. Airborne or satellite-based remote sensing techniques are also applicable for atmospheric CO2 sensing over very large areas. Prior to the start of injection, an extended baseline survey is required to characterize the natural variability in CO2 concentration due, for example, to diurnal and seasonal variations in ecosystem influence. This is illustrated in Figure 19.12, which shows the hour mean CO2 concentration measured over a 3-year period at the Otway project (see Etheridge et al., 2011). Where natural variability and model uncertainties are large, the sensitivity of atmospheric monitoring for leak detection can be significantly increased by the detection of co-injected tracers (see below), although with current technology this generally requires the collection of flask samples and subsequent laboratory analysis. In the Otway example, co-injected methane and sulfur hexafluoride (SF6) were successfully used to detect emissions during scheduled venting of the observation well.

19.4.2 Soil gas monitoring The CO2 content of soil gas can be monitored either using discrete point measurements or using continuous monitoring. Point measurements can be made by analyzing gas collected using a steel gas probe driven into the soil or by measuring the gas flux across the airsoil boundary using a surface chamber, while gas sensors buried in water tight but gas-permeable housings can be used for continuous

Storage monitoring and verification technologies

509

590 Otway Cape Grim baseline

560

CO2 (ppm)

530 500 470 440 410 380

16/12/09

17/10/09

18/8/09

19/6/09

20/4/09

19/2/09

21/12/08

22/10/08

23/8/08

24/6/08

25/4/08

25/2/08

27/12/07

28/10/07

29/8/07

30/6/07

1/5/07

2/3/07

1/1/07

350

Figure 19.12 CO2 concentration record from the Otway atmospheric monitoring station. Source: From Etheridge et al. (2011), with permission.

monitoring. Depending on soil conditions, a vapor probe can be driven to a depth of up to 4 m, with soil gas samples collected using a gas-tight syringe and transferred to sample bottles for laboratory analysis. The effectiveness of these monitoring techniques for CO2 leakage detection has been demonstrated in experiments conducted by the US Department of Energy, National Energy Technology Laboratory (see Strazisar et al., 2009). Similar controlled release experiments have also been conducted at the CSIRO Ginninderra experimental station in Canberra, Australia, to assess the performance of various techniques for the spatial interpolation of soil flux measurements in order to quantify total CO2 leakage rate (Schroeder et al., 2017).

19.4.3 Plant health monitoring using reflectance spectra The adverse impact of elevated CO2 concentration in soil gas on plant health has been well documented for many natural CO2 vents, such as those at Mammoth Mountain (see NETL, 2002), and has also been observed in experimental CO2 releases designed to test geological storage monitoring techniques (see Male et al., 2010). The absorption and reflectance of visible and infrared radiation by plants provides an indication of a range of plant attributes. In the visible spectrum, absorption of blue and red with higher reflectance of green wavelengths is due to the presence of leaf pigments including chlorophyll and is indicative of photosynthetic efficiency, while reflectance at infrared wavelengths is affected by the internal cell structure of leaves, which responds to environmental stressors such as drought, elevated CO2, etc.

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The monitoring of reflectance spectra is therefore a simple and effective method of monitoring plant health, although it cannot distinguish between stress caused by elevated CO2 concentration and other factors such as water availability or temperature. In the CO2 release experiments described by Male and co-workers, spectral signatures were able to detect plant stress when soil gas CO2 concentration had risen to between 4% and 8% by volume, which was three to four times the background level during the experiments. Reflectance spectral data can be gathered over a wide range of scales, from sitespecific surveys using portable or fixed devices to wide area surveys using airborne or satellite-based sensors.

19.4.4 Geochemical leak detection in shallow aquifers Experimental studies have shown that the introduction of CO2 into shallow aquifers will result in distinctive chemical changes that can be monitored for early identification of leakage from an underlying storage complex. As well as a drop in pH and carbonate content, significant increases in the concentrations of manganese (Mn), iron, and calcium have been observed (see Little and Jackson, 2010). The monitoring of isotopic ratios in groundwater may also provide early warning of CO2 leakage (see Pauline et al., 2011); Table 19.4 indicates a number of geochemical processes in groundwater that could be influenced by CO2 migration and detected through isotope monitoring. This remains an area for further research and field testing.

19.4.5 Tracer injection The co-injection of tracers—specific chemical elements or compounds that label injected fluids—can significantly improve the detectability of leakage as a result of the extremely low detection limits for typical tracers, and also because the baseline concentrations are not subject to the natural variability that is typical of CO2 concentration in most ecosystems. The injected CO2 stream will also contain inherent tracers, such as carbon isotopes and noble gases, which can be used alongside or in place of coinjected tracers. Table 19.4 CO2-induced geochemical processes susceptible to isotopic monitoring Geochemical processes

Isotopic indications

Adsorption/desorption Carbonate dissolution Redox conditions Precipitation reactions CO2 migration

Boron, lithium Carbon, strontium Chromium, iron, selenium, sulfur Calcium Carbon

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Tracer injection has a number of potential applications in storage monitoring. If more than one injection well is used in a project, marking each injection stream with a unique tracer enables the breakthrough of injected CO2, i.e., at an observation well, to be attributed to a specific injector. This increases the information value of the breakthrough event as a constraint on subsurface uncertainties by providing additional definition of plume movement. Alternatively, co-injected tracers that could be definitively detected at ultralow concentrations could provide a predictor of imminent CO2 breakthrough, allowing a pre-emptive remedial response. Table 19.5 Characteristics of major tracers types for storage monitoring Tracer type

Characteristics

Notes

Noble gases

Noble gases (He, Ne, Ar, Kr, Xe)

CO2 isotopes

Isotopes of CO2, such as 14CO2

Perfluorocarbons (PFCs)

PFCs are colorless, non-reactive gases derived from hydrocarbons by replacing the hydrogen atoms with fluorine atoms (e.g., C6F12, C7F14)

Sulfur hexafluoride (SF6)

SF6 is a colorless, non-reactive gas that is present in the atmosphere at a concentration of 7 ppt (7 3 10212). SF6 is the most potent known greenhouse gas, with a global warming potential approximately 23,000 times that of CO2 and an atmospheric lifetime of B3200 years

Relative costs versus detection levels dependent on atmospheric concentrations (Ar 0.9%, Ne 18 3 1026, He 5 3 1026, Xe 9 3 1028). Inherent noble gas tracers will reflect both CO2 source and capture process With an atmospheric concentration of 10214 by volume and a detectable limit of 3 3 10212, 14CO2 is a potentially attractive tracer from a cost and logistical perspective PFCs are not normally present in the natural environment (,1 in 1014) and, as such, they are detectable at concentrations as low as parts per 1015. They have been widely used in oil field tracer applications SF6 concentration in the atmosphere doubled from 3.5 ppt in 1994 to 7.0 ppt in 2010 as a result of industrial usage and related emission, primarily as a dielectric medium for high-voltage electrical equipment

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Carbon Capture and Storage

The use of tracers can also be expected to become increasingly important as geological storage projects proliferate, since they will have an important role in establishing responsibility for remediation in the event of leakage. The key characteristics of various types of tracer applicable to storage monitoring are summarized in Table 19.5. Tracers have been used in a number of storage demonstration projects. In the Frio Brine Pilot a suite of tracers including four PFCs, SF6, and three noble gases (Ne, Kr, and Xe) were injected with the CO2. Tracer arrival times and subsequent evolution of tracer concentration, at an observation well located 35 m from the injection point, provided a basis for assessing tracer partitioning between CO2 and brine and estimation of the evolution of CO2 saturation within the injected plume. Because of their extremely low detection limit, PFC detection in soil gas samples was also applied—with null result—to test for leakage of injected CO2 into the vadose zone. The US DOE’s SEQURE tracer technology project, demonstrated the use of perfluorocarbon tracers to detect injected CO2 breakthrough into ECBM production wells in the San Juan Basin coalbed test site, New Mexico.

19.4.6 Offshore sonar monitoring Offshore, sonar measurements of the water column have been shown to successfully detect gas seepages from natural gas reservoirs. Sub-bottom profiling is a sonar technique that images shallow sediments up to tens of meters below the seabed and can indicate gas migration paths in the shallow subsurface. Figure 19.13 shows an example of a sub-bottom profiling survey indicating the leakage of hydrocarbon gas from deep reservoirs.

Figure 19.13 Sub-bottom profiling survey indicating hydrocarbon gas leak paths. Source: Courtesy, Jonathan Bull and Justin Dix, National Oceanography Centre, University of Southampton.

Storage monitoring and verification technologies

19.5

513

Injection-withdrawal tests

The concept of an injection-withdrawal, or pushpull, test was first proposed in 1997 as a quantitative method for investigating a range of physical, chemical, and biological processes in aquifers (see Istok et al., 1997). When applied for storage formation characterization, the objective of a pushpull test is to assess the impact of scCO2 injection under actual, rather than simulated, in situ condition. These tests involve the injection into a potential host formation of a limited quantity of scCO2, typically no more than a few tonnes, followed by an incubation period of a few weeks or months and concluded by a backproduction period in which both remaining scCO2 and altered formation brine are recovered (see Assayag et al., 2009). The duration of the back-production period is designed to ensure production of a multiple of the injected volume, so that breakthrough curves characteristic of the processes under investigation can be measured. This is illustrated in Figure 19.14, which shows idealized breakthrough curves of an injected tracer, reagent and in situ reaction product. Chemical, ionic, and isotopic analysis of the back-produced fluids can identify the geochemical processes taking place, e.g., carbonate and silicate mineral dissolution, cation release and exchange, etc. Pushpull tests using CO2-saturated brine have been extensively used to investigate the geochemical processes leading to mineral trapping in basaltic rocks. Similarly, microbial analysis of pre- and post-injection fluids can provide insight into the impact of scCO2 injection on microbial populations. A PIP (produceinjectproduce) test is a variant of the simpler inject-withdraw test, with an initial withdrawal stage designed to provide a baseline of the in situ fluid properties if this is required for evaluation of the measurements made during the later withdrawal period.

Relative concentration (C/C0)

Tracer

Reactant

In situ reaction product

0

1

2

Extracted volume / Injected volume

Figure 19.14 Idealized breakthrough curves during a pushpull test. Source: After Istok et al. (1997).

3

514

Carbon Capture and Storage

A variant of this technique was evaluated at the Otway Basin Pilot in Victoria, Australia to investigate CO2 residual trapping. In the envisaged three-step test, a water injection-withdrawal test would first be conducted in the Warre C potential storage formation before CO2 injection. CO2 would then be injected and back-produced to establish residual gas saturation in the near wellbore region, following which the water injection-withdrawal test would be repeated and the difference between the two tests, including tracer partitioning, analyzed to determine Sgr (see Sharma et al., 2009).

19.6

References and resources

19.6.1 References General Jenkins, C., Chadwick, A., Hovorka, S.D., 2015. The state of the art in monitoring and verification—ten years on. Energy Procedia. 40, 312349.

Seismic monitoring Boait, F., White, N., Chadwick, A., Noy, D., Bickle, M., 2011. Layer spreading and dimming within the CO2 plume at the Sleipner field in the North Sea. Energy Procedia. 4, 32543261. Burnison, S.A., Bosshart, N.W., Salako, O., Reed, S., Hamling, J.A., Gorecki, C.D., 2017. 4-D Seismic monitoring of injected CO2 enhances geological interpretation, reservoir simulation, and production operations. Energy Procedia. 114, 27482759. Chadwick, A., et al., 2010. Quantitative analysis of time-lapse seismic monitoring data at the Sleipner CO2 storage operation. Society of Exploration Geophysicists. The Leading Edge. 29, 170177. Cheng, A., Huang, L., Rutledge, J., 2010. Time-lapse VSP data processing for monitoring CO2 injection. The Leading Edge. 29, 196199. Daley, T.M., Myer, L.R., Peterson, J.E., Majer, E.L., Hoversten, G.M., 2008. Time-lapse crosswell seismic and VSP monitoring of injected CO2 in a brine aquifer. Environ. Geol. 54, 16571665. Verdon, J.P., Kendall, J.-M., White, D.J., Angus, D.A., Fisher, Q.J., Urbancic, T., 2010. Passive seismic monitoring of carbon dioxide storage at Weyburn. Society of Exploration Geophysicists. The Leading Edge. 29, 200206. White, D., et al., 2017. Monitoring results after 35 ktonnes of deep CO2 injection at the Aquistore CO2 Storage Site, Saskatchewan, Canada. Energy Procedia. 114, 40564061.

Gravity and electromagnetic monitoring Alnes, H., Eiken, O., Stenvold, T., 2008. Monitoring gas production and CO2 injection at the Sleipner field using time-lapse gravimetry. Geophysics. 73, 155161. Alnes, H., Eiken, O., Nooner, S., Sasagawa, G., Stenvold, T., Zumberge, M., 2011. Results from Sleipner gravity monitoring: updated density and temperature distribution of the CO2 plume. Energy Procedia. 4, 55045511. Chadwick, A., Aarts, R., Eiken, O., Williamson, P., Williams, G., 2006. Geophysical monitoring of the CO2 plume at Sleipner, North Sea: an outline review. In: Lombardi, S., Altunina, L.K., Beaubien, S.E. (Eds.), Advances in the Geological Storage of Carbon Dioxide: International Approaches to Reduce Anthropogenic Greenhouse Gas

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Emissions. NATO Science Series IV: Earth and Environmental Sciences. Springer, Dordrecht, The Netherlands. Constable, S., Srnka, L.J., 2007. An introduction to marine controlled-source electromagnetic methods for hydrocarbon exploration. Geophysics. 72, WA3WA12. Daily, W., Ramirez, A.L., 2000. Electrical imaging of engineered hydraulic barriers. Geophysics. 65, 8394. Girard, J.-F., Coppoa, N., Rohmer, J., Bourgeois, B., Naudet, V., Schmidt-Hattenberger, C., 2011. Time-lapse CSEM monitoring of the Ketzin (Germany) CO2 injection using 2xMAM configuration. Energy Procedia. 4, 33223329. Newmark, R.L., Ramirez, A.L., Daily, W.D., 2002. Monitoring carbon dioxide sequestration using electrical resistance tomography (ERT): a minimally invasive method. 6th International Conference on Greenhouse Gas Control Technologies, Kyoto, Japan, September 30October 4, 2002. Nord, J., Du, S., Sturton, S., 2011. Feasibility study of CO2 monitoring using controlled source electro-magnetics, CSEM. SINTEF Petroleum Research Report. Available at www.sintef.no/publikasjoner/publikasjon/?pubid5CRIStin11124918. Schmidt-Hattenberger, C., et al., 2011. Application of a vertical electrical resistivity array (VERA) for monitoring CO2 migration at the Ketzin site: first performance evaluation. Energy Procedia. 4 (33633370). Schmidt-Hattenberger, C., Bergmann, P., Labitzke, T., Pommerencke, J., Rippe, D., Wagner, F., Wiese, B., 2017. Monitoring the complete life-cycle of a CO2 storage reservoir—demonstration of applicability of geoelectrical imaging. Energy Procedia. 114, 39483955.

Ground surface deformation monitoring Onuma, T., Ohkawa, S., 2009. Detection of surface deformation related with CO2 injection by DInSAR at In Salah, Algeria. Energy Procedia. 1 (21772184). Rutqvist, J., Vasco, D.W., Myer, L., 2010. Coupled reservoir-geomechanical analysis of CO2 injection and ground deformations at In Salah, Algeria. Int. J. Greenhouse Gas Control. 4, 225230.

Surface, near-surface, and seabed monitoring Etheridge, D., et al., 2011. Atmospheric monitoring of the CO2CRC Otway Project and lessons for large scale CO2 storage projects. Energy Procedia. 4, 36663675. Flude, S., Johnson, G., Gilfillan, S.M.V., Haszeldine, R.S., 2016. Inherent tracers for carbon capture and storage in sedimentary formations: composition and applications. Environ. Sci. Technol. 50, 79397955. Little, M.G., Jackson, R.B., 2010. Potential impacts of leakage from deep CO2 geosequestration on overlying freshwater aquifers. Environ. Sci. Technol. 44, 92259232. Male, E.J., et al., 2010. Using hyperspectral plant signatures for CO2 leak detection during the 2008 ZERT CO2 sequestration field experiment in Bozeman, Montana. Environ. Earth Sci. 60, 251261. NETL, 2002. Lessons Learned from Natural and Industrial Analogues for Storage of Carbon Dioxide in Deep Geological Formations. National Energy Technology Laboratory, Report LBNL #51170.

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Pauline, H., Pascal, A., Julie, L., Philippe, N., Vincent, L., 2011. Tracking and CO2 leakage from deep saline to fresh groundwaters: development of sensitive monitoring techniques. Energy Procedia. 4, 34433449. Schroder, I.F., Wilson, P., Feitz, A.F., Ennis-King, J., 2017. Evaluating the performance of soil flux surveys and inversion methods for quantification of CO2 leakage. Energy Procedia. 114, 36793694. Strazisar, B.R., Wells, A.W., Diehl, J.R., Hammack, R.W., Veloski, G.A., 2009. Near-surface monitoring for the ZERT shallow CO2 injection project. Int. J. Greenhouse Gas Control. 3, 736744.

Injection-withdrawal tests and tracers Assayag, N., Matter, J., Ader, M., Goldberg, D., Agrinier, P., 2009. Waterrock interactions during a CO2 injection field-test: Implications on host rock dissolution and alteration effects. Chem. Geol. 262, 406414. Istok, J.D., Humphrey, M.D., Schroth, M.H., Hyman, M.R., O’Reilly, K.T., 1997. Singlewell, “push-pull” test for in situ determination of microbial activities. Ground Water. 35, 619631. Matter, J.M., Takahashi, T., Goldberg, D., 2007. Experimental evaluation of in situ CO2-water-rock reactions during CO2 injection in basaltic rocks: implications for geological CO2 sequestration. Geochem. Geophys. Geosyst. 8 (Q02001), . Sharma, S., Cook, P., Jenkins, C., 2009. CO2CRC Otway Project. Presented at the Deep Saline Aquifers for Geological Storage of CO2 and Energy Conference. RueilMalmaison, France, May 2729, 2009.

19.6.2 Resources Furre, A.-K., Eiken, O., Alnes, H., Vevatne, J. N., Kiær, A. F., 2017. 20 years monitoring CO2-injection at Sleipner. Energy Procedia. 114, 39163926. Geoscience Australia controlled CO2 release database: www.ga.gov.au/about/projects/energyold/greenhouse-gas-monitoring/controlled-release-studies.

Ocean storage

20.1

20

Introduction

As described in Chapter 2, the world’s oceans contain an estimated 39,000 Gt-C (143,000 Gt-CO2), 50 times more than the atmospheric inventory, and are estimated to have taken up almost 38% (B600 Gt-CO2) of all anthropogenic CO2 emissions over the past two centuries. Options that have been investigated to store carbon by increasing the oceanic inventory are described in this chapter, including biological (fertilization), chemical (reduction of ocean acidity, accelerated limestone weathering), and physical methods (CO2 dissolution, liquid CO2 pools in the deep ocean).

20.2

Physical, chemical, and biological fundamentals

20.2.1 Physical properties of CO2 in seawater The behavior of CO2 released directly into seawater will depend primarily on the pressure (i.e., depth) and temperature of the water into which it is released. The important properties are as follows: G

G

G

The liquefaction pressure at a given temperature: the point at which, with increasing pressure, gaseous CO2 will liquefy The variation of CO2 liquid density with pressure, which determines its buoyancy relative to seawater The depth and temperature at which CO2 hydrates will form and decompose

Saturation pressure At temperatures of 0
10 C, CO2 will liquefy at pressures of 4
5 MPa, corresponding to water depths of 400
500 m, with a liquid density of 860 kg/m3 at 10 C and 920 kg/m3 at 0 C. At this depth liquid CO2 will therefore be positively buoyant, and free liquid droplets will rise and evaporate into gas bubbles as pressure drops below the saturation pressure.

Buoyancy Figure 20.1 shows the densities of CO2 and seawater versus depth for a range of ocean conditions. Liquid CO2 is more compressible than water and becomes neutrally buoyant at depths of 2500
3000 m. Below this depth range, released liquid droplets will sink to the ocean floor. Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00020-9 © 2017 Elsevier Inc. All rights reserved.

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Density (t/m3) 0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

0.0 CO2 density

Depth (km)

1.0 Sea water density

2.0 Liquid CO2 rises

Transition zone 3.0

Liquid CO2 sinks

4.0

Figure 20.1 CO2 and seawater density versus depth.

Hydrate formation and decomposition As discussed in Chapter 9, gas hydrates can be formed under suitable conditions of temperature and pressure when guest molecules are in contact with water. CO2 hydrates can form in all seawater deeper than B400 m, as long as there is sufficient CO2 present, and as shallow as 150 m in polar regions where water temperature is close to 0 C. A CO2 gas bubble or liquid drop at hydrate stable pressure and temperature will rapidly form a crystalline hydrate skin, which will slow but not halt the dissolution of CO2 into the surrounding seawater. Naturally occurring hydrates have been observed forming around CO2-rich gas bubbles venting from hydrothermal vents at B1500 m depth in the mid-Okinawa Trough. Dissolution of the hydrated particle will continue however, even at hydrate stable (P,T), unless the water surrounding the particle is CO2-saturated. Hydrates can also decompose by dissociation, rather than dissolution, if the particle is taken outside the hydrate stable (P,T) region, for example, by advection. The density of solid CO2 hydrate is 1110 kg/m3, and it will therefore sink in seawater, which has a density of B1030 kg/m3. However, the density of a hydrate mass formed from gas bubbles or liquid droplets wrapped in a hydrate skin will depend on the gas or liquid density, as well as the skin thickness and droplet size, which determine the gas:liquid:hydrate ratio in a hydrate particle. Depending on this “average” particle density, the neutral buoyancy depth in seawater may be between 1000 and 3000 m.

20.2.2 The ocean carbon cycle As described in Chapter 1, the deep ocean is by far the largest sink in the global carbon inventory, and two interlinked cycles—one physical and one biological— drive the fluxes into and out of that sink.

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519

The solubility pump The solubility pump, or physical pump, is the term used to describe the physical and chemical process by which CO2 is transported from the atmosphere to deep ocean waters. The process is illustrated in Figure 20.2, together with the interlinked biological pump described below. The two main elements of the solubility pump are the dissolution of CO2 into surface waters and the successive downwelling of surface water and upwelling of deep water via the global thermohaline circulation system. The surface layer of the ocean is well mixed by wind and wave action (hence also known as the mixed layer) and CO2 in the atmosphere reaches thermodynamic equilibrium with dissolved CO2 in this layer on a timescale of weeks to months, depending on mixed layer depth and wind conditions. The equilibrium solubility of a gas is directly proportional to its partial pressure (Henry’s law): CCO2 5 PCO2 =KHCO2 5 PCO2 KCO2

(20.1)

where CCO2 is the dissolved CO2 concentration, PCO2 is the partial pressure of CO2 in the atmosphere, KHCO2 is the Henry’s law constant, and KCO2 is the solubility of CO2. The solubility KCO2 is a function of pressure, salinity, and acidity (pH) and, most importantly, of temperature, with solubility increasing from B0.03 mol-CO2/kg at 20 C to B0.05 mol-CO2/kg at 10 C (for typical current atmospheric and oceanic conditions). The dissolution of CO2 in water initially forms carbonic acid (H2CO3), which will dissociate into bicarbonate and then carbonate ions, the partitioning depending on the water temperature and alkalinity. The total concentration of these species— dissolved free CO2 (CO2(aq)), carbonate ions (CO22 3 ), and bicarbonate ions

CO2

CO2

CO2 outgassing as T increases Upwelling with reducing CO2 solubility

Thermohaline circulation Biological pump

Atmosphere

Surface mixed CO2 uptake as layer water cools Pycnocline Downwelling with increasing CO2 solubility

Thermohaline circulation

High dissolved inorganic carbon

Carbonate

Figure 20.2 The ocean carbon cycle: solubility and biological CO2 pumps.

Deep ocean

520

Carbon Capture and Storage

(HCO2 3 )—is known as the dissolved inorganic carbon (DIC). The interactions that establish this balance are as follows: 1 22 1 CO2 1 H2 O2H2 CO3 2HCO2 3 1 H 2CO3 1 2H

(20.2)

At current average mixed layer conditions, DIC is B91% bicarbonate and 8% carbonate ions, with the remaining 1% being dissolved free CO2 plus carbonic acid. The DIC content of surface waters varies from a low of B1850 µmol-C/kg in the Bay of Bengal to a high of B2200 µmol-C/kg in the Weddell Sea. The second component of the solubility pump is the formation of deep waters through meridional overturning that occurs in the North and South Atlantic Oceans (Figure 20.3). A parcel of water moving northward in the Gulf Stream experiences strong evaporative cooling due to wind action, resulting in increasing uptake of CO2 from the atmosphere as a result of its temperature-dependent solubility, as well as an increase in salinity and density as a consequence of evaporation. By the time a parcel of water reaches the Norwegian Sea, the density becomes high enough to cause it to sink, forming North Atlantic Deep Water (NADW). This water flows back in a southerly direction into the abyssal Atlantic basin. A similar process occurs in the sub-Antarctic South Atlantic, forming Antarctic Bottom Water (AABW). The total rate of downwelling is estimated at 30
40 3 106 m3/day, and it is roughly evenly distributed between the North and South Atlantic locations. Other than at these two downwelling locations, a stable layering or stratification occurs in the ocean as a result of temperature and density gradients. This stratification can be seen in the tropical ocean temperature profile shown in Figure 20.4. A warmer, less dense upper layer is separated from the colder, denser deep water by an interval known as the thermocline, where temperature drops rapidly with depth. The thermocline thus marks the limit of the mixed layer, within which fairly

Figure 20.3 Global thermohaline circulation.

Ocean storage

521

0

4

8

Temperature (⬚C) 12 16

20

24

0

Depth (m)

500

Thermocline

1000

1500

2000

Figure 20.4 Temperature versus depth in a tropical ocean.

rapid thermodynamic equilibrium is reached between the surface water and the atmosphere. Deep ocean waters, with temperatures down to 2 C and pressures . 10 MPa, are highly undersaturated, and it is this excess solubility that enables the ocean to provide a sink for increased atmospheric CO2 over a centennial timescale. The deep waters from the Atlantic Basin circulate westward around the Antarctic Ocean basin, branching off and subsequently upwelling in the Indian and Pacific Oceans as well as in the Southern Ocean. The timescale of this circulation system is millennial. Early estimates of the time required for downwelling surface water to fully displace the deep ocean volume based on 14C radioactive tracer measurements put this “ventilation time” of the deep ocean at B1400 years. Subsequent improved understanding of the processes involved has reduced this timescale to B250 years for the Atlantic and B550 years for the Pacific. When deep waters upwell, CO2 outgases to the atmosphere at the seawater
air interface since the partial pressure of CO2 in the seawater is higher than the partial pressure in the atmosphere. In pre-industrial times this cycle had reached an equilibrium, with average surface and deep waters containing B2000 and 2100 µmol-C/ kg of DIC, respectively. The anthropogenic increase in CO2 partial pressure in the atmosphere, from 280 ppm in pre-industrial times to the current B400 ppm, has resulted in an increase in the average DIC of surface water to B2100 µmol-C/kg. As a result, the ocean has already sequestered an estimated 600 Gt of anthropogenic CO2 emissions over the past two centuries. However, the ability of the surface water to take up additional CO2 does not increase linearly as atmospheric CO2 concentration increases. This is because, as dissolved CO2 and therefore carbonic acid increases, the preferred reaction is as follows: 2 CO2ðaqÞ 1 H2 O 1 CO22 3 ! 2HCO3

(20.3)

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Carbon Capture and Storage

This reaction consumes carbonate ions (carbonate buffering), and reduces the impact on ocean acidity (pH) that would otherwise arise, since it converts carbonic acid to alkaline bicarbonate ions. If further CO2 addition reduces carbonate ion concentration to the point that surface waters become undersaturated, carbonate minerals such as CaCO3 will start to dissolve. Under these conditions, calcifying organisms will find it harder to produce shells and coral reefs may dissolve. For the 100 ppm increase in atmospheric CO2 from 380 to 480 ppm, the increase in DIC will be only B70% of the increase that resulted from the first historical 100 ppm increase.

The biological pump The “biological pump” is the term used to describe the biological mechanisms that control the export of particulate organic carbon (POC) from the surface waters down to the deep ocean. Figure 20.5 illustrates the biological pump and its close interconnection with the solubility pump described earlier. The starting point for the biological pump is the process of photosynthesis, through which the production of organic carbon takes place in well-lit (euphotic) shallow ocean waters. Photosynthesis starts with the absorption of a photon of light by a chlorophyll molecule, contained in the chloroplast of marine algae or within a photosynthetic bacterium. The energy from the photon is used in a complex sequence of biochemical reactions known as the Calvin cycle (Section 21.2.1), which eventually results in the production of simple sugars that are then used to synthesize other organic compounds and to support the metabolism of the organism.

Sunlight

Nutrients + CO2

Atmosphere

Surface mixed layer

Photosynthesis

Pycnocline Detrital flux

Nutrients + CO2

Solubility pump

Remineralization

Deep ocean Sedimentation Carbonate

Organic carbon

Figure 20.5 The ocean carbon cycle: biological pump.

Ocean storage

523

This set of reactions can be expressed in the highly simplified form: 6CO2 1 6H2 O 1 photons ! C6 H12 O6 1 6O2

(20.4)

which illustrates that CO2 is consumed and O2 produced in the overall chain of reactions. CO2 may be either absorbed directly from the air, as is the case for terrestrial plants, or obtained from CO2 dissolved in the surface seawater. Phytoplankton also requires nutrients such as nitrate, phosphate, and silicic acid, which are delivered to the euphotic zone by upwelling deep ocean waters, and micronutrients, such as iron, which are deposited as windborne (aeolian) dust from arid, upwind land masses. This process of generating organic carbon via photosynthesis is called primary production and is the base of the marine food web. The biomass of phytoplankton is successively consumed by small, then larger marine animals, which release organic carbon as fecal pellets. The marine food web also results in the production of particulate inorganic carbonate (PIC) material from the shells or tests of calcifying marine organisms such as foraminifera and freeswimming mollusks. These organisms are able to produce carbonate shells from surface seawater because surface waters are supersaturated with carbonate ions. This element of the biological pump is referred to as the hard tissues pump, with the remainder being the soft tissues pump. Dead phytoplankton and other biomass may be remineralized into inorganic carbon, nitrate, and ammonia by bacterial action, contributing to the total DIC and linking the biological pump with the solubility pump. Remaining dead biomass and decay products will be exported from the euphotic zone as POC, where once again it becomes a nutrient source for deep water and ocean-floor ecosystems. The falling particulate matter and decay products, both organic and inorganic, are collectively known as “marine snow.” Through this process an estimated 0.2 Gt-C/year is deposited onto the ocean floor. In contrast to surface waters, deep waters are undersaturated in carbonate. Falling PIC therefore dissolves as it reaches these undersaturated waters, further increasing DIC in deep ocean waters.

Long-term atmosphere
ocean CO2 equilibrium As noted earlier, deep ocean waters provide a CO2 solubility sink that is coupled to the atmosphere via the solubility and biological pumps. As a result, changes in atmospheric [CO2] are damped on a timescale determined by the slow turnover of deep ocean waters. This is illustrated in Figure 20.6, which shows schematically the evolution of atmospheric [CO2] resulting from a 100-year “pulse” of B6 Gt-CO2/ year emissions to the atmosphere. This simple model considers only the partitioning of the emitted volume between atmosphere and ocean and excludes other feedbacks, so the numbers are purely illustrative. In this simple model 70%
80% of the emitted mass is taken up by the ocean over a millennial timescale; using more complete longer-term models, the total uptake of emitted CO2 into terrestrial and oceanic sinks is estimated to be 85%
90%.

600

1.0

500

0.8

400

0.6

300

0.4

200

0.2

100 0

200

400

600

800

0.0 1000

Fraction of emitted CO2 remaining in the atmosphere

Carbon Capture and Storage

[CO2] (ppm)

524

Years from start of emission period

Figure 20.6 Schematic long-term partitioning of an emitted CO2 pulse. Table 20.1 Options for ocean storage of CO2 Physical concept

Technological scheme

Direct CO2 dissolution

Rising plume Neutral buoyancy (isopycnal) spreading plume Sinking plume Piped feed to seabed lake Sinking cooled liquid plus solid CO2 slurry Constrained or unconstrained hydrate accumulation Injection into ocean-floor sediments

Liquid CO2 isolation

20.3

Direct CO2 injection

The scale of anthropogenic CO2 uptake into the oceans has been increasing with the rise in CO2 partial pressure over the past 200 years and is currently occurring at a rate of B2.4 Gt-CO2/year. Long-term storage of CO2 in the ocean relies on its retention in deep waters that have a ventilation time of several centuries, plus the natural tendency of CO2 to partition into seawater from the atmosphere. Two basic concepts and a range of technological options have been proposed, as summarized in Table 20.1.

20.3.1 Direct CO2 dissolution The potential for deep ocean waters to carry a higher dissolved carbon load is illustrated in Figure 20.7, which shows the approximate DIC profile for mid-Pacific and mid-Atlantic Ocean locations. An increase in DIC of 50 µmol-C/kg, B2% of current levels, for the body of water from 1000 to 3000 m depth, represents an increase in the carbon inventory of . 80 Gt-C, equivalent to 14 years of global anthropogenic CO2 emissions at year 2000 levels. Direct dissolution below the thermocline is one option to make use of this storage capacity to achieve long-term CO2 sequestration. Release at depths greater than

Ocean storage

525

Total inorganic carbon (µmol/kg) 2000

2100

2200

2300

2400

2500

Depth (m)

1000

2000

mid-Pacific 50 million km2 = 60 Gt-C

mid-Atlantic 20 million km2 = 24 Gt-C

3000 Atlantic

Pacific

4000

5000

Figure 20.7 Ocean storage capacity for dissolved CO2.

500 m would be in liquid form and would be accompanied by the immediate formation of a hydrate shell around individual liquid droplets. At depths shallower than B2500 m, depending on droplet size and hydrate skin thickness, the resulting plume would be positively buoyant and would rise while individual droplets slowly dissolve. Below B3000 m release depth, similar behavior would be seen with a sinking plume, while at intermediate depths neutral buoyancy (isopycnal) spreading of the plume would occur.

Results of experiments and field trials of CO2 dissolution Laboratory and in situ experiments, mathematical modeling studies, and small-scale field trials have been conducted to investigate the properties, behavior, and ecological impact of CO2 released into seawater, generally as liquid droplets, larger liquid masses, or liquid
hydrate
water composites. Experiments conducted at the Monterey Bay Aquarium Research Institute (MBARI; see References and resources section), typically involving the release and observation of liquid droplets by ROVs, have yielded insights into the dissolution rate of individual hydrate-enclosed droplets and their rising or sinking rate, depending on release depth. Rising droplets are found to have terminal velocities in line with the Stokes law behavior of a rigid sphere, consistent with the presence of a rigid hydrate shell. Dissolution rates of hydrate-enclosed liquid droplets are found to be reduced by a factor of three to four compared to the rate expected for a nonhydrated droplet. Other phenomena such as droplet rafting and formation of a gas phase as a droplet crosses the liquefaction pressure depth have also been observed. Experimental releases of relatively larger liquid CO2 volumes have also been performed to investigate the use of sonar as a method of tracking a rising plume.

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This technique could have importance in monitoring CO2 storage in subsea aquifers or depleted gas fields, or to monitor CO2 emitted from hydrothermal vents. Hydrate-enclosed CO2 droplets were found to be easily detectable using highfrequency sonar (38 and 675 kHz) as a result of the high acoustic velocity difference between liquid CO2 and seawater. Evolution of a droplet plume formed by the release of 5 L of CO2 could be easily tracked over a 150 m ascent, and the overall plume behavior was accurately described by mathematical models. Further experiments using lower acoustic frequencies were envisaged to monitor seawater density changes resulting from CO2 dissolution, as well as possible biological responses to the plume. Other small-scale release experiments have investigated the behavior of CO2 liquid
hydrate
seawater composite material formed by the injection and vigorous mixing of seawater into a liquid CO2 stream. Unlike hydrate-enclosed liquid CO2 droplets, which as noted become negatively buoyant at B2500 m, this composite material contains a higher proportion of hydrate and becomes negatively buoyant at B1000 m. This material was extruded in the form of cylindrical pellets 6.5 mm in diameter and ranging in length from 5 to 85 mm, with a density that depends on the degree of conversion of the liquid CO2 to hydrate. More complete conversion to hydrate is desirable since it results in a denser pellet, thereby maximizing the effective depth of disposal. As for liquid CO2 droplets, movement and dissolution of the pellets were monitored and estimates of the dissolution rate were obtained. Individual pellets were found to sink between 10 and 70 m before complete dissolution. These small-scale experiments have given insight into the fate of individual droplets and small hydrate masses but are unable to address larger-scale effects that would determine the dynamic behavior of a large plume. Mathematical simulations indicate that if a large number of the extruded hydrate pellets were released, the resulting negatively buoyant stream would sink significantly faster and further than individual pellets, as a result of the entrainment of water into a plume and the increasing density of entrained water as CO2 dissolves into the plume. A plume containing a mass flux of 100 kg-CO2/s was predicted to descend B500 m before the pellets were fully dissolved.

Free ocean CO2 enrichment experiment By analogy with the Free Air CO2 Enrichment (FACE) experiments that have been performed to test the effects of elevated [CO2] in terrestrial ecosystems (described in Section 21.5.1), a variety of Free Ocean CO2 Enrichment (FOCE) systems have been designed and constructed, most notably at MBARI, to study the effects of increased [CO2] in seawater on different marine ecosystems—from the deep-sea floor to near-shore sand flats and seagrass meadows. In these systems, seafloor currents carry a parcel of CO2-enriched seawater through a series of baffles within a rectangular flume. The CO2-enriched parcel mixes and reacts with the surrounding seawater and the system is actively

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Figure 20.8 MBARI FOCE flume configuration. Source: From Kirkwood et al. (2014), with permission.

controlled to achieve a consistent elevated seafloor [CO2] level in a B1 m2 test area in the middle of the flume (Figure 20.8). The FOCE system is typically operated to achieve a pH offset within the test area of 20.1 to 20.5 pH units from the ambient conditions and is designed to be left in place for weeks or months to investigate the impact of reduced pH on such factors as foraging success and feeding efficiency in biological communities including crustaceans, fishes, and mollusks. Future systems are planned to include oxygen and temperature controls within the test area, to enable a wider variety of in situ experiments into the impact of climate change on these ecosystems.

20.3.2 Liquid CO2 injection The negative buoyancy of unhydrated liquid CO2 below B2500 m and CO2 hydrates below B1000 m opens up the possibility of sequestering CO2 as gravity stable deposit on the ocean floor—either as a liquid lake, in an ocean-floor depression or deep trough, as a liquid or hydrate accumulation contained within a geomembrane, or below ocean-floor sediments.

Ocean-floor CO2 lakes A liquid ocean-floor lake could be formed either by releasing liquid directly into a depression or by releasing negative-buoyancy droplets or hydrated particles sufficiently close to the bottom that a substantial proportion of the released liquid mass would reach bottom before complete dissolution. Naturally occurring ocean-floor CO2 lakes have been observed in the vicinity of hydrothermal vents, as a result of the liquefaction and pooling of CO2-rich gases

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released from these vents. These naturally occurring CO2 lakes are too shallow to be gravitationally stable and are held in place by overlying sediments and by hydrate crusts or cements in these sediments. Small-scale ocean-floor experiments have also been performed with liquid CO2 pools to assess the impact of direct CO2 injection on deep-sea ecosystems. Small pools of liquid CO2 were created by releasing B20 L of liquid into open-topped cylindrical “corrals” on the seabed at 3600 m depth. At this depth the excess density of the liquid CO2 keeps the mass constrained within the corral, but slow dissolution results in a dense CO2-rich, low-pH plume being swept downcurrent across the ocean floor. The results of these small-scale experiments show that significant reductions in pH will occur in the close vicinity of an ocean-floor CO2 lake, resulting in high mortality rates in the affected marine ecosystem. Given these results it is not surprising that attempts to perform mesoscale trials have met with considerable environmental opposition. Numerical studies have also been performed to assess the dissolution rate from a liquid CO2 lake, both under static conditions and under the influence of ocean-floor currents. These studies show that vertical mixing above such a lake is reduced as a result of the formation of a high-density (B1.5 kg/m3) boundary layer and conclude that gravity currents that may result from this high-density water mass will be an important factor to consider in future studies and experiments. In an environment that is not disturbed by ocean-bottom currents, the dissolution rate from the lake would be reduced as a result of the hydrate layer that would form at the lake surface as well as by the stratification that would result from denser, CO2-rich water filling the depression above the lake surface. A lifetime in excess of 10,000 years would be possible for a 50 m deep lake with a dissolution rate of , 5 mm/year, although these residence times would be substantially reduced (25
500 times faster) in the presence of moderate or stronger ocean-floor currents.

Contained ocean-floor storage One option that has been proposed to eliminate the adverse effects of CO2 on the ocean-floor ecosystem is to isolate the injected liquid within a synthetic geomembrane. The envisaged containment system would be a sausage like envelope, 500 m in circumference and perhaps 10 km in length, each of which could contain 16 MtCO2. Required membrane characteristics would include resistance to the chemical effects of CO2 and low permeance to prevent osmosis. The requirement for mechanical strength would not be great, in view of the small density difference between the internal and external fluids if deployed close to the neutral buoyancy point. Polymer geomembranes have been used in dam, reservoir, and land-fill construction since the 1960s, with lifetimes projected to be thousands of years. Current fabrication techniques—although not at the scale envisaged above—include co-extrusion of several layers (e.g., low- or high-density polyethylene (LDPE, HDPE) as a water and salt barrier, sandwiching a layer of ethylene vinyl alcohol copolymer (EVOH) as a CO2 barrier).

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A similar seafloor containment system has also been proposed for storing CO2 in the form of hydrates. Although hydrate particles will dissolve in open seawater, they would be stable if the water within the containment system is CO2-saturated. Storage as a hydrate would have the advantage that leakage would likely be much slower in the event of a rupture in the membrane, since both heat and unsaturated water are required for hydrate dissolution. However, this advantage may be outweighed by the additional volume that would need to be stored, the hydrate volume being about four times the equivalent liquid CO2 volume.

Storage in ocean-floor sediments Below the ocean floor the temperature starts to rise in line with the geothermal gradient, eventually resulting in hydrate dissociation and in a reduction in density to the point where, even if below the open water neutral buoyancy depth (Figure 20.1), liquid CO2 once again becomes buoyant in the pore fluid. Depending on the water depth and temperature gradient, the hydrate formation zone (HFZ) and also the negative buoyancy zone (NBZ) can extend several hundred meters into the ocean-floor sediments, as shown in Figure 20.9. The NBZ, from B2500 m down to its base in the ocean-floor sediments, provides an unbreachable physical (gravitational) barrier that would prevent deeper injected CO2 from returning to shallower environments. This opens up the possibility of storing CO2 in a gravitationally and thermodynamically stable state below unconsolidated ocean-floor sediments. Storage under seabed sediments was first proposed by Koide et al. (1997), who described various

Density (t/m3) 0.9

1.0

Temp. (°C)

1.1 0

5

10

Distance from shore 15

Sea water density CO2 density

Sea water temp.

Hydrate region

2.0 Depth (km)

No hydrate region

1.0

Hydrate formation zone (HFZ) c. 2.5 km

NBZ

3.0 HFZ

Negative buoyancy zone (NBZ) c. 3.5 km

4.0

Figure 20.9 NBZ and HFZ in ocean-floor sediments.

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options at increasing water depths. In their “Superdeep” case, below 3700 m, they proposed weighting liquid CO2 with clay or ash to ensure an effective fluid density greater than that of the unconsolidated sediments, which were also considered as a heavier than water fluid. This concept was modified in 2006 by House and co-workers, who proposed to inject liquid CO2 below the HFZ at a location where this was deeper than the NBZ (see Figure 20.9). Rising liquid CO2 would start to form hydrates at the bottom of the HFZ, which would inhibit further upward movement and cause lateral spreading (Figure 20.10A). Any CO2 that did penetrate this hydrate cap would eventually reach the base of the NBZ at which point it would cease to be buoyant, while dissolution and advection would carry CO2 in the aqueous phase away from the HFZ (Figure 20.10B). Ultimately, on a timescale of up to 106 years, all of the CO2 would dissolve, the aqueous phase mixing with the ambient fluid until it became neutrally buoyant (Figure 20.10C). House and co-workers estimated storage capacity within the 200-mile US EEZ to exceed 104 Gt-CO2 while subsequent analysis suggests a global capacity of between 0.1 and 2.8 3 104 Gt-CO2. The main uncertainty in this approach is whether these ocean-floor sediments, which are typically carbonate or clay rich, have sufficient intrinsic permeability to permit injection at the required rates and the extent to which hydraulic fracturing could be applied without risking the release of (albeit negatively buoyant) liquid CO2 to the ocean floor.

20.3.3 Prospects for large-scale ocean storage field trials The only mesoscale ocean storage field trial to reach an advanced planning stage was the so-called CO2 Ocean Sequestration Field Experiment, that was proposed under the auspices of a project agreement (the International Collaboration on CO2 Ocean

Ocean-floor NBZ

HFZ

Hydrates Hydrates CO2(l)

CO2(aq)

CO2(aq)

CO2(l) CO2(aq) (A)

(B)

(C)

Figure 20.10 Evolution of CO2 injected into deep ocean-floor sediments. Source: After House (2006).

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Sequestration) signed by the US Department of Energy, the New Energy and Industrial Technology Development Organization of Japan, and the Norwegian Research Council during the 1997 Third Conference of Parties to the UNFCCC in Kyoto. The first series of experiments to be designed under this agreement had as its objectives to: G

G

G

G

Investigate CO2 droplet plume dynamics through qualitative (video) and quantitative methods (pH and velocity measurements) Clarify the effects of hydrates on the dissolution of CO2 droplets through similar measurements Trace the evolution of the CO2-enriched seawater by performing 3D mapping of velocity, pH, and DIC Assess the potential biological impact of changes in seawater pH by quantifying changes in bacterial biomass, production, and growth efficiency both in the water column and on the ocean floor.

The final project design envisaged the release of 20
40 t-CO2 over a period of 1
2 weeks using a 4 cm diameter coiled steel tubing deployed from a ship down to the injection depth at 800 m (Figure 20.11). The buoyant plume of CO2 droplets, injected from a diffuser assembly on the ocean floor at a rate of B1 kg/s, was expected to rise B100 m before dissolving. Further field experiments under the project agreement were expected to focus on acute and chronic environmental impacts and subsequent recovery and were planned to be conducted over a timescale of at least a year, comparable to the lifetimes of affected organisms. The experiment was planned to be hosted by the Natural Energy Laboratory of Hawaii Authority (NELHA) and to take place in the summer of 2001 in the ocean research corridor operated by NELHA at Keahole Point in Kona, on the west coast of Hawaii. However, as a result of strong public opposition the project was unable to secure all the required permits and had to abandon the Hawaii experiment. CO2 supply ship

800 m discharge depth

Sloping seabed

Figure 20.11 Proposed CO2 Ocean Sequestration Field Experiment configuration.

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Carbon Capture and Storage

Subsequently a scaled-down version of the experiment was planned, to release and monitor 5.4 t-CO2 off the coast of Norway, but failed to secure approval from the Norwegian environment ministry. Results from small-scale experiments confirm that the dynamic behavior of individual droplets, small hydrate particles, and small-scale masses (in the order of 5 kg) is reasonably well understood and can be modeled with confidence. However, the dynamics and environmental impact of plumes resulting from large-scale CO2 injection are unknown and will remain so until public and political perception of the risks of conducting large-scale experiments are overtaken by the perceived risks of not doing so.

20.4

Chemical sequestration

Like the igneous rocks that provide a number of potential feedstocks for mineral carbonation, carbonate rocks, most commonly limestone with a high content of calcium carbonate, are also subject to weathering when exposed on the earth’s surface. The weathering or dissolution of limestone by carbonic acid is an important reaction in the geochemical carbon cycle, described in Chapter 1, and proceeds according to the reactions: H2 O 1 CO2 ! H2 CO3

(20.5)

CaCO3 1 H2 CO3 ! Ca21 1 2HCO2 3

(20.6)

Natural limestone weathering removes an estimated 0.7 Gt-CO2/year from the atmosphere and results in the transportation of B2.6 Gt/year of dissolved calcium bicarbonate into the ocean. In the absence of countervailing fluxes, this process would remove all CO2 from the atmosphere on a timescale of B4500 years. The same chemistry can be applied to the capture and sequestration of CO2 from power plant or cement plant flue gases in a process called the accelerated weathering of limestone (AWL). Flue gases would be bubbled through a reactor containing crushed limestone particles that is continuously wetted by a supply of water. For each t-CO2 captured, the process consumes 2.3 t-CaCO3 plus 0.4 t-water and produces 3.7 t of calcium bicarbonate in solution. The bicarbonate-rich effluent stream is envisaged to be disposed of by discharge into the ocean and this could have a beneficial environmental effect, since the addition of bicarbonate would counteract ocean acidification. However, if discharged as a 75% saturated bicarbonate solution (5 3 1023 M at a CO2 partial pressure of 150 kPa), this would require a water supply of 104 t-water/t-CO2. This equates to a colossal B108 t-water/day for a 500 MWe power plant (B1/10 of a cubic km of water) and is some 300 times the volume that would be used for power plant cooling. In addition, some 30 kt-CaCO3 would be required to be transported to the plant, compared to B5 kt-coal/day fuel requirement.

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The prodigious quantities of limestone and particularly water required represent significant hurdles to the large-scale application of the AWL process. The dissolution of olivine has also been proposed as an ocean storage option (see Ko¨hler et al., 2013). Studies indicate the need to grind olivine to a particle diameter of B1 µm to ensure full dissolution of a falling particle within the water column, resulting in an energy cost comparable to direct air capture. The silicic acid reaction product would also have a major fertilization effect in those regions of the ocean where this nutrient is lacking.

20.5

Biological sequestration

20.5.1 Ocean iron fertilization The concept of ocean fertilization as a carbon sequestration strategy arises from the observation that, despite the availability of nutrients, primary production of biomass through photosynthesis is limited in some ocean areas, particularly in the Southern Ocean and in the North Pacific. These areas are designated high-nutrient, low-chlorophyll (HNLC). It was first suggested in the 1930s, by English biologist Joseph Hart, that this might be due to a deficiency of iron in these areas. Iron is required as a micronutrient by the phytoplankton responsible for primary production, and this suggestion was confirmed in the 1980s by oceanographer John Martin, based on experiments demonstrating increased phytoplankton growth in water samples from several HNLC ocean locations after enrichment with iron. Unlike the primary phytoplankton macronutrients (nitrate, phosphate, and silicic acid) that are delivered into the euphotic zone by the upwelling of nutrient-rich deep ocean waters, iron is delivered to the ocean as a component of wind-borne (aeolian) dust, carried offshore from arid land masses. The low level of primary production in the Southern Ocean and North Pacific can then be understood as a result of the lack of upwind sources of wind-blown iron-bearing dust. Recent analysis of seabed cores from the Southern Ocean has confirmed that an increase in dust-borne iron from Patagonia to the Subantarctic Atlantic resulted in a drop in atmospheric [CO2] of some 40 ppm during the most recent glacial maximum.

Results of iron fertilization trials Fertilization of these HNLC ocean areas by seeding with iron would be expected to increase primary production and increase the flux of organic carbon into the deep ocean where it would be effectively sequestered over a millennial timescale. Since the mid-1990s, 13 iron fertilization trials have been conducted, 11 in HNLC areas (7 in the Southern Ocean, 3 in the subarctic North Pacific, and 2 in the equatorial East Pacific), and 1 combined Fe 1 P study in the LNLC subtropical North Atlantic. The typical parameters of these mesoscale experiments are shown in Table 20.2.

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Carbon Capture and Storage

Table 20.2 Parameters of mesoscale iron fertilization experiments Parameter

Range

Description

Iron quantity Patch area Mixed layer thickness Tracers

350
2800 kg 50
100 km2 10
100 m SF6, 234Th

Commonly as FeSO4 solution

Tracing patch movement and particle export

Table 20.3 Iron fertilization: impacts and controlling factors Impacts and controlling factors Characteristics of the phytoplankton bloom

Local ecological impact of the bloom

Initial chemical and optical conditions Pre-existing phytoplankton communities Dilution rate of enriching solution Iron supply rate and duration Macronutrient supply Redistribution of phytoplankton grazers in response to increased food availability Increased growth and reproduction of phytoplankton grazers Changes in species composition and food web structure Depletion of macronutrient supply Increased bacterial activity and biogenic gas generation

Tracers such as SF6 and thorium-234 (234Th) are added to the iron enrichment solution for experimental monitoring. SF6 can be detected in minute quantities and is used to enable subsequent mapping of the location of the iron-enriched patch as it is moved and stirred by ocean currents. The naturally occurring radioactive isotope thorium-234 has a high affinity for particles, and the loss of the isotope from the enriched water indicates the rate at which particles are sinking from the upper ocean. These experiments have confirmed that iron enrichment does affect the rate of primary production, causing a bloom of phytoplankton. However, they have also demonstrated that iron enrichment results in other changes in the ecology and biogeochemistry of the enriched patch and that many factors then come into play that determine the fate of the bloom and the extent to which export of POC to the deep ocean takes place (Table 20.3). One example of an adverse impact from iron enrichment is an increased release of nitrous oxide (N2O) as a result of microbial nitrification of ammonia from the decaying bloom. N2O is a GHG with a lifetime in the atmosphere of 120 years and, relative to CO2, has a global warming potential of 296 over a 100-year timescale. The effectiveness of induced blooms in increasing the export of POC to the deep ocean remains highly uncertain and has been demonstrated in only two of the

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mesoscale experiments. Estimates of the required rate of iron addition to the rate of carbon export range from 2 to 2000 µmol-Fe/mol-C; the lower end reflects the carbon content of the total biomass produced per mole of added Fe, while the upper end is a more conservative estimate of the net long-term export to the deep water and ocean floor.

Other fertilization options While iron fertilization aims to supplement a deficient micronutrient, mesoscale experiments have also been conducted in macronutrient-poor waters, an example being the phosphate-deficient eastern Mediterranean Sea. However, as well as unexpected interactions in the marine ecosystem, macronutrient-based fertilization would face an additional challenge due to the substantially greater amount of macronutrient required for phytoplankton growth. The molar ratio of carbon to the macronutrients nitrogen and phosphorus in phytoplankton is a relatively stable ratio and has been found to be equal to the ratio of these elements in deep ocean water, given by the Redfield ratio (C:N:P 5 106:16:1). This congruence demonstrates the closeness of the interaction between the biochemistry of phytoplankton and the chemistry of the deep ocean water body that regulates their environment and is an example of ecological stoichiometry. This ratio, named after American oceanographer Alfred Redfield (1890
1983), is the reason that the marine photosynthetic reaction is sometimes written as: 106CO2 1 16HNO3 1 H3 PO4 1 122H2 O ! C106 H263 O110 N16 P 1 138O2 (20.7) where C106H263O110N16P represents the average plankton composition. In contrast to the relative constancy of the Redfield ratio, the molar ratio of iron to carbon (Fe:C) in phytoplankton is more variable. A value of 2
3 µmol-Fe/mol-C is considered a minimum to sustain cells at zero growth rate, close to the value of 2 µmol-Fe/mol-C measured in HNLC surface water. Increasing iron availability leads to increasing uptake, up to a saturation growth rate at an Fe:C ratio of B20 µmol-Fe/mol-C. An average value of 6 µmol-Fe/mol-C is commonly used in modeling studies, which compares to 9400 µmol-P/mol-C from the Redfield ratio. If 1% of net biomass production resulting from phosphorus fertilization reaches the deep ocean, sequestration of 1 t-C could require the application of 2.4 t of phosphorus—equivalent to 7.7 t phosphoric acid or 8.9 t ammonium phosphate!

Prospects for implementation In a 2007 statement of concern, the Scientific Groups of the London Convention (the Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter) stated the view that current knowledge about the effectiveness and potential environmental impacts of iron fertilization was insufficient to justify large-scale operations. Parties to the Convention developed and adopted an

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assessment framework in 2010 (Assessment Framework for Scientific Research Involving Ocean Fertilization) which requires an Initial Assessment, determining whether a proposed activity falls within the definition of ocean fertilization and has proper scientific attributes, an Environmental Assessment, addressing Problem Formulation, Site Selection and Description, Exposure Assessment, Effects Assessment, Risk Characterization, and Risk Management (see Table 20.4) and a final decision-making process, determining whether the proposed activity is legitimate scientific research, and is consistent with the aims of the Convention. In 2013, amendments to the Convention were introduced to prohibit ocean iron fertilization and other marine geoengineering activities, unless conducted for scientific research and in accordance with the assessment framework. The large-scale application of iron fertilization would have a major impact on ocean biogeochemistry and ecosystems. Understanding these impacts with the level of confidence that would be required to satisfy the London Convention requirements, or for verifiable carbon offset accounting, will likely require tens or hundreds of mesoscale experiments. Given these challenges, the prospect for large-scale implementation of ocean iron fertilization seems remote. However, multidisciplinary studies based on satellite observations have concluded that a drop in primary production in the oceans over recent decades is partly attributable to a decline in the supply of aeolian dust to the oceans. This natural source of iron is estimated to have declined by 25% over the two decades from 1980 to 2000 as a result of changes in land use and increasing primary production in arid-zone grasslands. When the complex interactions between marine biogeochemical and ecological systems are better understood, selective iron fertilization may play a part in a strategy to mitigate some of the consequences of climate change, such as declining primary ocean productivity in traditionally productive regions.

Table 20.4 London convention impact assessment recommendation Impact assessment 1 2 3 4 5 6 7

Estimated amounts and potential impacts of iron and other materials to be released with the iron Potential impacts of gases that may be produced by the expected phytoplankton blooms or by bacteria decomposing the dead phytoplankton Estimated extent and potential impacts of bacterial decay of the expected phytoplankton blooms, including reducing oxygen concentrations Types of phytoplankton expected to bloom and the potential impacts of any harmful algal blooms that may develop Nature and extent of potential impacts on the marine ecosystem, including naturally occurring marine species and communities Estimated amounts and timescales of carbon sequestration, taking account of partitioning between sediments and water Estimated carbon mass balance for the operation

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20.5.2 Wave-driven ocean upwelling An alternative approach to enhancing the rate of CO2 sequestration in the ocean that does not rely on enrichment using external fertilization was originally proposed by J. D. Isaacs in 1976 and uses wave-powered pumps to draw cool, nutrient-rich waters to the ocean surface from below the thermocline. Figure 20.12 illustrates the wave-driven ocean upwelling system concept. Each pumping unit comprises a large-diameter (3
10 m) vertical tube of 100
200 m length, sealed at its base by a flapper valve that only allows water to pass into the tube, and attached to a surface float that lifts the water-filled tube on each wave crest. As the float and tube start to descend into the next trough, the flapper valve opens, the tube drops, and the water in the upper section of the tube is released onto the ocean surface. A large-scale application would require an array of such pumping units tethered to nearest neighbors at a separation of 1.5
2.5 km, and potentially covering thousands of square kilometers of ocean. However, deep water is also richer in DIC, and bringing this to the surface would result in CO2 release to the atmosphere. Warming of the lifted cooler water could also result in CO2 release due to the drop in solubility at higher temperatures. It is therefore questionable whether such an approach would lead to a net export of carbon from the mixed layer to the deep ocean. An initial field trial of the pumping units, the Ocean Productivity Perturbation Experiment (OPPEX) took place in 2008 and was designed to evaluate the feasibility of inducing a phytoplankton bloom in the HNLC area of the North Pacific. No further development work has been reported since then. A megascale application of wave-driven upwelling, extending to . 100,000 km2 in the Gulf of Mexico, has also been proposed to reduce the high sea-surface temperatures that contribute to the formation and growth of hurricanes.

Rising wave and float

Moving wave crest

Falling wave and float

Cold water overflow as pump tube descends

Flexible pump tube 0.25 to 1.5m diameter

Rising pump tube lifts cold water column

Falling pump tube

Colder water with higher nutrient levels Flapper valve closed

Depth 650 to 1000m

Figure 20.12 Wave-driven ocean upwelling system.

Flapper valve opens

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Carbon Capture and Storage

20.5.3 Ocean afforestation Similar to terrestrial afforestation discussed in the next chapter, ocean afforestation or ocean macroalgal afforestation (OMA) has been proposed as a carbon-neutral or, in a BECCS variant, carbon-negative solution for energy supply, particularly applicable to coastal communities and island nations. OMA involves the cultivation of kelp or seaweed over large areas of shallow, euphotic waters and the use of the harvested crops in bioenergy production, either with or without CCS. This has an advantage over terrestrial biomass in that it would not compete with food production for land and water use and may also result in a local increase in fish stocks as a result of increased productivity of the marine ecosystem. China, Indonesia, and the Philippines are currently the dominant producers of seaweed, which is currently used mainly for food, fertilizer, and hydrocolloid (agar, carrageenan) production. Global production tripled from 7 Mt/year in 1997 to B24 Mt/year in 2012, and this is likely to accelerate as its potential as a third/ fourth-generation biofuel feedstock is realized. The use of macroalgae as a biofuel feedstock was first proposed by Howard Wilcox in the late 1960s, both as an additional energy source and as a climate change response. A variety of conversion options have been investigated for biofuel production from macroalgae, with biochemical methods such as anaerobic digestion or fermentation being particularly suitable due to the high water and carbohydrate content of the biomass. High conversion efficiency has been achieved by genetic engineering of microorganisms to metabolize macroalgal carbohydrates (alginate polysaccharides) and directly synthesize bioethanol. Research into industrial-scale macroalgal cultivation for biofuels was conducted in the US DOE funded Marine Biomass Program from 1979 to 1985, including open ocean cultivation and harvesting methods, and anaerobic digestion to produce biomethane. This effort was subsequently abandoned when natural gas price deregulation in the United States led to the discovery and development of vast new gas resources. Worldwide interest has however grown in the last decade, partly in response to a recognition of the limitations of first- and second-generation biofuels, and a large number of R&D and demonstration projects have been proposed, initiated, or completed, a few of which are summarized in Table 20.5. The first of these projects follows on from a pilot-scale demonstration, commenced in 2002 by the Technology Research Institute of Tokyo Gas Company, in which 0.6 t/day of seaweed (Ulva sp. and Laminaria sp.) was anaerobically digested to produce biomethane. Offgas from the fermentation (20 m3/t, 60% CH4 and 40% CO2) was combined with natural gas to power a 10 kW gas engine, the makeup being required both to control the overall heating value of the fuel and to achieve the fuel volume required for continuous operation. Interestingly, this effort was in large part motivated by the need to clean up Japanese beaches that are regularly polluted by a green tide of rotting seaweed! The major technical challenge in bringing OMA to an impact scale is the need to move cultivation from near-shore to open ocean environments, and the inherent difficulties in designing, constructing, and operating aquaculture systems in this difficult offshore environment. A particularly successful project aimed at addressing

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Table 20.5 Macroalgal biomass development and demonstration projects Project, location

Lead organization

Objectives and key project parameters

Ocean Sunrise, Japan

Tokyo Fisheries Promotion Foundation

BioMara, UK and Ireland

Scottish Association of Marine Sciences

Seafarm, Sweden

KTH Royal Institute of Technology

Seaweed Biorefinery Project, Netherlands

ECN

EnAlgae, EU

Swansea University, UK

Cultivation of Sargassum fulvellum and conversion to ethanol; by-products to be used for cattle feed and fertilizer; coastal rope-culture farming techniques applied to offshore areas; transportation and storage systems to be developed Feasibility of macroalgae and microalgae as alternatives to terrestrial biofuel feedstock; methane and methanol from seaweed; testing of prototype systems for offshore kelp cultivation Develop a sustainable system for the use of seaweed as a renewable resource Adapt the biorefinery concept to seaweed feedstock for the production of carbon-neutral chemicals, thirdgeneration biofuels and bioenergy Development of algal bioenergy technologies at nine pilot facilities and advancement of the emerging North West European marketplace Production of a suitable growth substrate for seaweed to grow on and offshore engineering systems for the open ocean mooring and positioning of growth substrates Develop a system to produce biofuel from biowaste using GHG emissions and also macroalgae as a catalyzer

ATBSEA, Atlantic Scottish Association of Europe and Morocco Marine Sciences

BioWALK4Bio-fuels, Denmark, India

University of Rome

this challenge has been the EU FP7 funded ATBSEA project which developed and demonstrated advanced textile substrates that replace the traditional net- and ropebased systems and enable denser cultivation and easier harvesting.

20.6

References and resources

20.6.1 References Aya, I., et al., 2004. In situ experiments of cold CO2 release in mid-depth. Energy. 29, 1499
1509.

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Barry, J.P., et al., 2004. Effects of direct ocean CO2 injection on deep-sea meiofauna. J. Oceanogr. 60, 759
766. Barry, J.P., et al., 2014. Use of a free ocean CO2 enrichment (FOCE) system to evaluate the effects of ocean acidification on the foraging behavior of a deep-sea urchin. Environ. Sci. Technol. 48, 9890
9897. Boyd, P.W., 2012. Ocean fertilization for sequestration of carbon dioxide from the atmosphere. In: Lenton, T., Vaughan, N. (Eds.), Geoengineering Responses to Climate Change: Selected Entries from the Encyclopedia of Sustainability Science and Technology. Springer Science 1 Business Media, New York, USA. Brewer, P.G., Friederich, G., Peltzer, E.T., Orr Jr., F.M., 1999. Direct experiments on the ocean disposal of fossil fuel CO2. Science. 284, 943
945. Brewer, P.G., et al., 2005. Deep ocean experiments with fossil fuel carbon dioxide: creation and sensing of a controlled plume at 4 km depth. J. Marine Res. 63, 9
33. Capron, M.E., Stewart, J.R., Rowe, R.K., 2013. Secure seafloor container CO2 storage. OCEANS’ 13 MTS/IEE San Diego Technical Program #130503-115. Cicerone, R., et al., 2004. The ocean in a high CO2 world. Oceanography. 17, 72
78. Gattuso, J.-P., et al., 2014. Free-ocean CO2 enrichment (FOCE) systems: present status and future developments. Biogeosciences. 11, 4057
4075. Handa, N., Ohsumi, T. (Eds.), 1995. Direct ocean disposal of carbon dioxide. In: Proceedings of First and Second International Workshops on Interaction between CO2 and Ocean, 1991 & 1993, Terrapub, Tokyo. House, K.Z., Schrag, D.P., Harvey, C.F., Lackner, K.S., 2006. Permanent carbon dioxide storage in deep-sea sediments. Proc. Natl Acad. Sci. USA. 103, 12291
12295. Karl, D.M., Letelier, R.M., 2008. Nitrogen fixation-enhanced carbon sequestration in low nitrate, low chlorophyll seascapes. Marine Ecol. Prog. Ser. 364, 257
268. Kirkwood, W.J., et al., 2014. Design, construction, and operation of an actively controlled deep-sea CO2 enrichment experiment using a cabled observatory system. Deep Sea Research I. 97, 1
9. Ko¨hler, P., Abrams, J.F., Vo¨lker, C., Hauck, J., Wolf-Gladrow, D.A., 2013. Geoengineering impact of open ocean dissolution of olivine on atmospheric CO2, surface ocean pH and marine biology. Environ. Res. Lett. 8, 014009. Koide, H., et al., 1997. Deep sub-seabed disposal of CO2—the most protective storage. Energy Convers. Manage. 38 (Suppl.), S253
S258). Palmer, A., Keith, D., Doctor, R., 2007. Ocean storage of carbon dioxide: pipelines, risers, and seabed containment. In: Proceedings of ASME 26th International Conference on Offshore Mechanics and Arctic Engineering. 10
15 June 2007, San Diego, CA. Rau, G.H., Knauss, K.G., Langer, W.H., Caldeira, K., 2007. Reducing energy-related CO2 emissions using accelerated weathering of limestone. Energy. 32, 1471
1477. Seifritz, W., 1990. CO2 disposal by means of silicates. Nature. 345, 486. Wargacki, A.J., et al., 2011. An engineered microbial platform for direct biofuel production from brown macroalgae. Science. 335, 308
313. White, A., et al., 2010. An open ocean trial of controlled upwelling using wave pump technology. J. Atmos. Oceanic Technol. 27, 385
396.

20.6.2 Resources ATBSEA Technologies (turnkey seaweed farms): www.atsea-project.eu. Carboocean IP (EU-funded assessment of marine carbon sources and sinks, focusing on the Atlantic and Southern Oceans over the past 200 and next 200 years): www.carboocean.org.

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Cquestrate (“open source” initiative seeking to enhance the carbon sink capacity of the oceans and mitigate ocean acidification): www.cquestrate.com. EnAlgae (development of algal bioenergy technologies): www.enalgae.eu. Future Earth (platform for international scientific collaboration on global sustainability): www.futureearth.org. GLODAP (Global Ocean Data Analysis Project): http://cdiac.esd.ornl.gov/oceans/glodap/. IMO, Scientific Groups to the London Convention and London Protocol, Assessment Framework for Scientific Research Involving Ocean Fertilization: www.imo.org/en/OurWork/ Environment/LCLP/EmergingIssues/geoengineering/OceanFertilizationDocumentRepository. Monterey Bay Aquarium Research Institute (MBARI): www.mbari.org. Ocean Chemistry of the Greenhouse Gases: www.mbari.org/ghgases. Free Ocean Carbon Dioxide Enhancement (FOCE): www.mbari.org/highCO2/foce/home.htm. National Maritime Research Institute (NMRI): www.nmri.go.jp/index_e.html. Ocean Acidification Network: http://ocean-acidification.net. Ocean Carbon & Biogeochemistry: www.us-ocb.org. Ocean Fuel (ocean cultivation systems for seaweed biomass): www.oceanfuels.com. SEAFARM Project (seaweed as a renewable energy resource in Sweden): www.seafarm.se. Seaweed Energy Solutions (large-scale seaweed cultivation for renewable energy and other uses): http://seaweedenergysolutions.com. The Ocean in a High CO2 world, UNESCO Intergovernmental Oceanographic Commission International Symposium Series: http://ocean-acidification.net/international-symposia/ second-meeting-on-oa-in-a-high-co2-world. UNESCO Intergovernmental Oceanographic Commission; International Ocean Carbon Coordination Project: http://ioc-unesco.org/, www.ioccp.org. Woods Hole Oceanographic Institution: www.whoi.edu. WHOI, Ocean Iron Fertilization site: www.whoi.edu/ocb-fert/page.do?pid 5 38315. Cafe´ Thorium; WHOI marine chemistry and geochemistry group: http://cafethorium.whoi.edu.

Storage in terrestrial ecosystems

21.1

21

Introduction

Terrestrial ecosystems play an important part in the global carbon cycle, being both the repository of an organic carbon inventory currently estimated at B2600 Gt-C (600 Gt-C in biomass and 2000 Gt-C in soils to 2 m depth—including B600 Gt-C in boreal permafrost) and the source and sink for closely balanced CO2 fluxes of the order of 120 Gt-C/year taken up from the atmosphere through photosynthesis and emitted through plant and microbial respiration. The combined effect of these fluxes results in a net uptake of carbon into terrestrial ecosystems from the atmosphere estimated at B3 Gt-C/year for the decade to 2013. Changes in this carbon inventory and related fluxes as a result of human activity have also been a major contributor to the atmospheric [CO2] increase during industrial times, with an estimated 150 Gt-C having been released due to land-use changes since 1850. This is a significant quantity when compared to the B275 Gt-C emitted through fossil fuel combustion and cement production since the mid-1800s and indicates the potential for the terrestrial ecosystems to have a significant impact in mitigating future increase in atmospheric [CO2]. Terrestrial ecosystems also respond to local, regional, and global climate variability and change on a variety of timescales and through a multitude of feedback loops. Quantifying the global impact of climate
ecosystem feedback and indeed establishing whether the overall feedback is positive or negative—accelerating or slowing climate change—is not currently possible with any degree of confidence due to the complexity and limited understanding of the processes that cycle carbon between the atmosphere and terrestrial ecosystems, particularly those processes occurring within soils. These processes constitute an important field of research, not only because of the possibility of enhancing the carbon inventory in terrestrial ecosystems as a sequestration measure, but also because of the possibility that future changes in land-management practices may be required in the event that significant positive feedbacks emerge as global mean temperature and [CO2] continue to increase. Carbon storage in terrestrial ecosystems can be enhanced by increasing the flux of CO2 from the atmospheric into long-lived terrestrial carbon pools, either in or derived from plant biomass, or by reducing the rate of CO2 emissions from carbon pools in terrestrial ecosystems back into the atmosphere. Examples of long-lived carbon pools in terrestrial ecosystems are as follows: G

G

G

Above- and belowground biomass, such as trees Long-lived products derived from biomass (primarily from wood) Biochemically recalcitrant (see Glossary) and stabilized organic carbon fractions in soils (inorganic soil carbon)

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00021-0 © 2017 Elsevier Inc. All rights reserved.

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Many management practices that can increase carbon inventories in terrestrial ecosystems are based on existing technology and can be applied immediately, while ongoing research will progressively improve our understanding of carbon dynamics in these ecosystems, and provide the basis for defining practices that maximize terrestrial carbon storage potential as well as quantifying that potential.

21.2

Biological and chemical fundamentals

As discussed in Chapter 1, within the global carbon cycle the total inventory of carbon in soils to a depth of 1 m is estimated to be B1600 Gt-C, roughly 4% of that in the oceans. Biomass holds a further estimated B600 Gt-C, while annual fluxes of B120 Gt-C/year occurs between the atmosphere and terrestrial ecosystems as a result of photosynthesis and respiration. The transfer of CO2 from the atmosphere into terrestrial vegetation and soils begins with the process of carbon fixation through photosynthesis, in which plants convert CO2, water, and energy in the form of absorbed photons into organic compounds.

21.2.1 Photosynthesis C3 photosynthesis In the plant chloroplast, photosynthesis starts with the so-called light reactions, in which an electron is released from a chlorophyll molecule as a result of the adsorption of a photon. The electron is exchanged between a number of complex organic compounds present in the chloroplast and eventually results in the reduction of nicotinamide adenine dinucleotide phosphate (NADP; C21H29N7O17P3) to NADPH, and the synthesis of adenosine-50 -triphosphate (ATP; C10H16N5O13P3) from adenosine diphosphate (ADP; C10H15N5O10P2). A sequence of reactions known as the Calvin cycle (or Calvin
Benson
Bassham cycle) then takes place within the chloroplasts, in which the enzyme RuBisCO (ribulose-1,5-bisphosphate carboxylase/oxygenase) catalyzes the fixation of CO2 to produce glyceraldehyde 3-phosphate (G3P), using the energy stored in NADPH and ATP. The Calvin cycle is shown schematically in Figure 21.1, and the overall equations for the light reaction and the Calvin cycle can be written as follows: 2H2 O 1 2NADP1 1 2ADP 1 2Pi 1 light ! 2NADPH 1 2H1 1 2ATP 1 O2 (21.1) and 3CO2 1 6NADPH 1 9ATP 1 6H1 ! G3P 1 6NADP1 1 9ADP 1 3H2 O 1 8Pi (21.2)

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CO2 3 molecules

ribulose 1, 5-bisphosphate 3 molecules

3C

3-phosphoglycerate 6 molecules

15C

18C

3 ADP 6 ATP 3 ATP 6 ADP ribulose 5-phosphate 3 molecules

1,3-diphosphoglycerate 6 molecules

15C

18C 6 NADPH

2 P

6 NADP+ 6 P

glyceraldehyde 3-phosphate 5 molecules

glyceraldehyde 3-phosphate 15C 6 molecules

18C

glyceraldehyde 3-phosphate 1 molecule

3C

Figure 21.1 The Calvin
Benson
Bassham photosynthetic cycle.

where NADP1 is the oxidized form of NADPH, Pi is an inorganic phosphate, and G3P
C3H7O6P is the end product of the cycle. G3P, the first photosynthetic product, is a three-carbon compound—hence the name C3 photosynthesis. It is the precursor for synthesis of glucose and other organic compounds, such as cellulose, and is thus the starting point for the growth of terrestrial biomass. Some photosynthetically fixed carbon is lost from the chloroplast by photorespiration, a process that regenerates the CO2 acceptor ribulose-1,5 bisphosphate that is lost in the oxygenase reaction pathway in which RuBisCO catalyzes the fixation of O2 rather than CO2. The product of the oxygenation is recycled in the mitochondria to produce serine, an alternative precursor to G3P, with CO2 being released. In total B20%
40% of the carbon fixed by C3 photosynthesis is respired by this process of photorespiration. In contrast to the oceans where primary production is limited by the availability of nutrients rather than CO2 (Chapter 20), land plants are able to increase GPP (see Glossary) with increasing CO2 availability. Although the response of mature forests

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is still unclear, vegetation in arid or semi-arid zones is particularly responsive to higher CO2 concentrations, since the amount of water loss due to transpiration for a given CO2 uptake is reduced as [CO2] increases. This enables a longer growing season and greater biomass production for a given rainfall. However, while this increase in primary production can contribute positively to carbon stocks, studies have shown that the benefit may be mitigated in some ecosystems if the availability of nitrogen is limited—the progressive nitrogen limitation theory. In this case, relatively stable soil carbon is decomposed to meet microbial and plant needs for nitrogen, resulting in higher soil respiration and offsetting the effect of increased GPP on soil carbon stocks.

C4 and CAM photosynthesis Two variants of the basic photosynthetic process have evolved that minimize water loss and the less efficient photorespiratory pathway, and typically occur in plants adapted for arid or semi-arid conditions. In so-called C4 plants, which include sugarcane, maize, and sorghum, CO2 is captured in the inner mesophyll layer via the formation of oxaloacetate and malate. These compounds contain four carbon atoms, hence the name C4 photosynthesis. The malate is transported into bundle sheath cells (Figure 21.2), where the CO2 is released and the standard Calvin cycle proceeds within the chloroplasts. By this mechanism RuBisCO is spatially isolated from oxygen present in the mesophyll, reducing photorespiration. High CO2 concentrations are achieved at the site of the Calvin cycle without the need for the stomata to be wide open, thus reducing water loss. Crassulacean acid metabolism (CAM) is another variant, occurring in plants such as pineapple, orchids, and cacti. In CAM plants, the stomata are opened at night, when the temperature is lower and humidity is generally higher, and water loss will therefore be minimized. As in C4 photosynthesis, the oxaloacetate and malate pathway is used to capture and store carbon dioxide. During the day the Mesophyll cell

CO2

PEP carboxylase Oxaloacetate 3 molecules

3 molecules

3 molecules

9C

12C

ADP

Malate 3 molecules Bundle sheath cell

ATP 9C

Pyruvate 3 molecules

CO2 3 molecules

3C

Calvin cycle

G3P 1 molecule

3C

Figure 21.2 Photosynthetic mechanisms in C4 plants.

9C

3C

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stomata are closed, reducing oxygen availability for photorespiration, and the CO2 is released, enabling Calvin cycle (C3) photosynthesis. The benefit that accrues to a C4 or CAM plant to offset the additional cost incurred in the production of malate is a substantial reduction in the loss of water through transpiration. A feature of photosynthesis that has become an important research tool for tracking plant-derived carbon in the environment is its discrimination in favor of the lighter 12C isotope. Although the heavier 13C isotope has a natural abundance of B1% in the atmosphere, when CO2 availability is not the limiting factor for primary production, photosynthesis discriminates against the heavier isotope with the result that carbon-fixed plant biomass is relatively depleted in 13C. This discrimination is strongest in C3 plants, with C3 biomass being typically 25m depleted in 13C (i.e., δ13C 5 222 to 230m compared to the VPDB carbonate standard; see Glossary), while in C4 and CAM plants the depletion is typically δ13C  28 to 211m.

Aboveground and belowground carbon allocation Up to 50% of the mono- and disaccharides (e.g., glucose and sucrose, respectively) produced by plants are delivered to the root system, where they are used to build root biomass, exuded and accessed by soil microbes, particularly the mycorrhizal fungi that form a symbiotic relationship with the plant root, with 5%
20% of a plant’s total carbon budget being allocated to these fungal associations. The exuded carbohydrates are partly consumed by heterotrophic respiration (see Glossary), releasing some fixed CO2 back to the atmosphere, and partly used to build microbial biomass. In return the plant gains access to the filamentary hyphae of the fungal mycelium, effectively increasing the surface area and fine-scale penetrative capacity of the root system for the uptake of water and nutrients. Since a plant’s primary reproductive task—the production of flowers, fruits, and seeds—takes place mainly above ground, the belowground allocation of GPP will be optimized to maximize reproductive success under specific ecological and environmental conditions. Some of the factors affecting belowground allocation are described in Table 21.1. Table 21.1 Factors influencing belowground carbon allocation in plants Factor Nutrient availability

Description

Increased nutrient availability, for example, through fertilization, reduces belowground allocation since the plant is more easily able to meet its nutrient requirements Water Similar to nutrients, less GPP needs to be invested belowground when availability water availability is high Soil disturbance Intensive cultivation may result in a shift in soil microbial community composition toward bacteria rather than fungi, which can result in a compensating increase in belowground allocation

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21.2.2 Biogeochemical features and processes in soils The complex symbiotic and competitive processes taking place in the immediate vicinity of root systems, the rhizosphere, have a major impact on the fate of soil organic matter (SOM) and are therefore a key to understanding the potential for carbon storage in soils. Fixed carbon accumulates as aboveground and belowground biomass and is incorporated into soils through litterfall from leaves and branches, from root growth and mortality, and from microbial biomass produced from root exudates.

Soil microbiota Microbial communities play an important but only partially understood role in the biogeochemical processes taking place within soils. The soil microbiome comprises two dominant microbial groups—bacteria and fungi—each having a different influence on soil processes. Bacteria are generally seen to respire a greater proportion of the carbon they metabolize as CO2 rather than using it to build biomass, and dead bacterial biomass is more rapidly broken down and metabolized by other organisms. Fungi respire a lower proportion of metabolized carbon, their cellular material is more recalcitrant, they produce extracellular enzymes that aid in the humification of lignitic material (see below), and they help to increase the residence time of carbon in soil through the part their fine hyphae in maintaining fine-scale soil structure (see also below). In addition, mycorrhizal fungi have a symbiotic relationship with most plants, providing nutrients to the plant “in exchange” for root exudates, and therefore contribute directly to primary productivity. The influence of microbes on soil processes, particularly on carbon storage in soils, and the way in which these processes will be affected by climate change— increasing temperature and [CO2]—are areas of active research.

Humification Carbon typically represents B57% by weight of organic matter incorporated into soils. This material is progressively broken down and decomposed by detritusfeeding soil animals, as well as by the action of microbes with B70% being mineralized to CO2 within 1 year as a result of root and microbial respiration. Note that in the context of soil processes, “mineralization” refers to the conversion of organic carbon to CO2, in contrast to the usage in Chapter 10 where mineralization refers to conversion of CO2 to a carbonate mineral. The residues from plant biomass and the by-products from microbial activity (microbial organic matter-MOM) are a complex mixture of organic compounds including sugars, amino acids, proteins, cellulose, lignin, lipids, tannins, and fragments of these molecules. Humic material is the end product of the process of decomposition and comprises the remnants of plant-, microbe-, and animal-derived compounds, broken down under partially oxidizing conditions into smaller organic molecules that are held together in supramolecular structures by weak (non-chemical) binding forces. Lignin is the least susceptible of

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Net primary Production

Belowground allocation

Aboveground allocation

Harvested biomass

Aboveground live C

Surface litter

Belowground live C Tillage

CO2 Surface microbial C CO2

Nutrient supply

Root litter + incorporated surface litter CO2

Root exudates CO2

Soil microbial C CO2

CO2

Slow C pool

Passive C pool

Eroded and leached C

Figure 21.3 Partial model of soil carbon pools, fluxes, and controls.

biomass residues to decomposition and is therefore a major component of humus and of soil organic carbon (SOC) stocks. These residues make up the majority of the slow and passive carbon pools in soils, as shown in Figure 21.3 and further discussed below. The figure shows a highlevel model of soil carbon pools, fluxes and controls, from GPP to the long-lived passive pool of soil carbon, and indicates a number of points at which respiratory activity contributes to the flux of CO2 back to the atmosphere. For simplicity, only two process linkages are shown in the figure: tillage, incorporating surface litter into the subsurface litter pool, and the supply of nutrient from subsurface microbial activity into GPP. Complete decomposition of these organic fragments would eventually result in full mineralization to CO2 and is prevented either by biochemical recalcitrance or physicochemical protection, or by low activity and abundance of decomposer organisms. Biochemical recalcitrance results from the blocking of microbial catabolic pathways due to the lack of essential enzymes, while the physicochemical protection of SOM occurs as a result of chemical adsorption onto mineral surfaces, facilitated by the presence of polyvalent cations such as calcium, iron, and magnesium, or the complete envelopment of SOM particles within aggregated soil particles. The ability of soils to physically protect organic material is an important determinant of soil carbon retention and is influenced by a range of factors described in Table 21.2. Various studies have shown that root-derived carbon is preferentially stabilized in soil compared to aboveground-derived carbon, due to the physical protection of root hairs within soil aggregate, the biochemical recalcitrance of root components,

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Table 21.2 Factors influencing the physical protection of SOM Factor

Description

Clay content and mineralogy

Clays promote the growth of microbial biomass by providing protection from predation and desiccation, by regulating the soil pH, and by absorbing contaminants detrimental to microbial growth Small pores (,10 μm) in soil micro- and macroaggregates provide refuge to bacteria and fungal hyphae from predation by larger predators such as protozoa and nematodes Repeated wetting and drying leads to soil erosion with SOM export, and breakdown of soil microaggregates, exposing SOM particles to further decomposition Soil disturbance, for example, as a result of tillage, results in the breakdown of soil macroaggregates leading to SOM erosion/deposition, and increased soil aeration leading to SOM decomposition

Pore-size distribution in aggregate particles

Soil microclimate, including wetting and drying cycles Soil aggregate stability

and the protection of root exudates or decomposition products by adsorption onto clay particles. The resulting SOM provides a source of nutrients for plant growth, as well as helping to retain water in the soil, further contributing to productivity. Complete mineralization of SOM will occur if it is exposed to fully oxidative conditions, promoting aerobic microbial activity, for example, as a result of disturbance of the aggregated soil structure by tilling. The addition of readily available carbon compounds to soil microorganisms may also promote their decomposer activity on SOM (the so-called primer effect). Conversely, the stability and activity of the enzymes and oxidants needed for microbial decomposition of organic material are reduced under acidic conditions and low temperatures, such as those occurring in northern peatlands, resulting in reduced rates of decomposition.

Soil structure The structure of soils is an important factor in determining the residence time of SOC, playing a role in protecting SOM from microbial access and in the balance between bacterial and fungal pathways by which this material is cycled through the food web. Particulate matter in soils can be aggregated at a microaggregate level (aggregate particle diameter ,0.25 mm) or at a larger macroaggregate level, as illustrated in Figure 21.4. The hyphal networks of mycorrhizal fungi play an important role in stabilizing macroaggregates, and loss of these networks can result in a breakdown of macroaggregates and a loss of SOC through increased bacterial activity. As a result of the clay-binding process described earlier, microaggregate particles provide a degree of

Storage in terrestrial ecosystems

Non-microaggregated

551

Macroaggregate

Plant and fungal debris Clay micro-structures Silt-sized aggregates Particulate organic matter and saprophytic fungi Mycorrhizal hyphae Pore space and organic binding agents

Microaggregates

Plant root 0.5 mm

Figure 21.4 Macro- and microaggregate particles in soil. Source: After Jastrow and Miller (1998).

Table 21.3 Factors increasing soil carbon stocks and related practices Factor

Related practices

Reduced soil disturbance to sustain soil structure Reduced soil aeration to reduce rate of decomposition Increased return of biomass and retention of belowground inputs to the soil Addition of exogenous organic matter

Tillage, grazing, logging Tillage Conservation tillage

Addition of mineral nutrients

Composts and manures (grazing) Fertilization

physical protection to SOM, which becomes less susceptible to microbial action when incorporated into these particles. Microaggregates are thus the essential repository of recalcitrant carbon in soils, alongside unprotected black (pyrogenic) carbon. When soil structure is disturbed by changes in land-use, land-management practices or environmental conditions, soil carbon stocks will tend toward a new quasi-equilibrium. In particular, practices or conditions that affect the protection of SOC within aggregates or the rate of decomposition in the soil will lead to reduced carbon stocks. These and other factors affecting carbon stocks are summarized in Table 21.3.

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Carbon Capture and Storage

21.2.3 Modeling climate
ecosystem interactions Most current global climate models that include interactions with the terrestrial carbon cycle rely on two simple feedback mechanisms: 1. Increasing [CO2] stimulates photosynthetic production (CO2 fertilization), increasing the flux of CO2 from the atmosphere into the terrestrial ecosystem and providing a negative feedback to rising [CO2]. 2. Rising temperatures stimulate respiratory activity, resulting in increased respiratory flux of CO2 from terrestrial ecosystems to the atmosphere and a positive feedback on mean temperatures.

Global terrestrial carbon uptake (Gt-C/year)

While both of these mechanisms are still the subject of study, the net predicted effect is currently a global uptake of carbon into terrestrial ecosystems, with rising [CO2] and mean global temperatures, which may be gradually overtaken by the increasing respiratory release of CO2, the pace of this reversal depending on the assumed parameters in the various models. Figure 21.5 shows schematically the range of predictions of net carbon uptake from a number of such climate models from the Coupled Carbon Cycle Climate Model Intercomparison Project (CMIP4). This comparison was based on the IPCC SRES-A2 carbon emissions scenario in which global CO2 emission from energy production rises to B16 Gt-C/year in 2050, without significant CCS deployment, and a very similar picture emerges in the CMIP5 comparison, which uses the IPCC AR5 RCP8.5 scenario (see Chapter 1, Heimann, 2008 and Friedlingstein et al., 2014). The range of model predictions of cumulative terrestrial carbon uptake to 2100 differ by B500 Gt-C and various models predict that terrestrial carbon could then be either a net source or sink of B5 Gt-C/year, or anything in between. Clearly this difference represents a significant uncertainty for global climate change prediction, necessitating an improvement in the fundamental understanding of the processes and interactions involved.

10

5

0

–5 1850

1900

1950

2000

2050

2100

Figure 21.5 Range of predicted terrestrial carbon uptake from climate
ecosystem models.

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Figure 21.3 showed a high-level model of soil carbon processes at the next level of detail beyond the simple two-factor ([CO2], T) approach described above, which provides a framework to integrate more detailed models of specific pools and processes. For example, Figures 21.6 and 21.7 show further levels of detail of the soil carbon pools and the interactions between soil microbial carbon and the progressively longer-lived slow carbon and passive carbon pools. The figures indicate some of the factors that influence these pools and processes, which are further discussed later. Many of the interactions occurring within soils are highly complex and in some cases counterintuitive, as is well illustrated by considering microbial priming—one of the factors indicated in Figure 21.7 as controlling the degree to which “passive” carbon may become available for further biological processing. Some soil carbon may be stabilized due to the absence of microbial activity, for example, in deeper soils where a lack of readily available substrates limits microbial activity. A change to a deeper rooting pattern may be induced by a reduction in local precipitation or by increasing [CO2], leading to higher NPP and increased belowground allocation. Cultivating plants with higher belowground carbon inputs and deeper roots may also cause increased belowground allocation. Deeper rooting in turn will cause the

Slow C pool Macromolecular C compounds

Plant Microbial

Slow C pool

Non-macroaggregated

Microaggregate formation and breakdown

Passive C pool Passive C pool

Biologically recalcitrant

POM

Nonmicroaggregated

MAOM POM

Microaggregated

MAOM

Sorption protected Aggregate protected

Macroaggregate formation and breakdown

Microaggregated Macroaggregated

Macroaggregated

Microaggregate formation and breakdown

POM

Nonmicroaggregated

MAOM POM

Microaggregated

MAOM

Figure 21.6 A simple conceptual model of soil carbon pools. Soil microbial C Microbial biomass

Soil microbial C CO2 Slow C pool

CO2

Decomposition of unprotected C Crop type; cropping intensity

Passive C pool

Soil hydration; rooting depth Tillage practices; soil aggregate stability Nitrogen input; microbial priming

CO2

Slow C pool Plant lignin Fungal Bacterial

Microbe derived C

Fungal Bacterial Fungal Bacterial CO2

Fungal:bacterial biomass ratio; Tillage practices

Predation of unprotected microbial C

Biochemical recalcitrance Physical protection; clay content and mineralogy Passive C pool

Figure 21.7 Second-level model of soil microbial, slow and passive carbon pools.

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Carbon Capture and Storage

addition of labile carbon—that proportion of soil C that is most rapidly mineralized back to CO2—in the form of roots and root exudates into deeper soils, stimulating microbial activity, which may then result in the decomposition of previously stable soil carbon. Similar priming effects have been invoked to explain numerous experimental studies where soil carbon has reduced as a result of labile carbon addition or where an expected increase in SOM has not occurred, for example, in FACE experiments (see Section 21.5.1 and Hopkins et al., 2014). A realistic coupling of soil carbon and climate models will require many more factors than simply [CO2] and mean temperature to adequately reflect these complex interactions. For example, a longer but still far from complete list of factors would include: G

G

G

G

G

G

G

Sensitivity of any CO2 fertilization effect to local conditions such as water and nutrient (N, P) availability Impact of warming and increased [CO2] on microbial community dynamics and SOC decomposition, including priming effects Direct and indirect impact of climate change on the accessibility of more recalcitrant (slow and passive) carbon (e.g., impact on physicochemical protection mechanisms) Sustainability of above effects on various timescales; e.g., long-term limit on microbial community dynamics due to nutrient/substrate availability Changes in mean precipitation and in the timing and frequency of rainfall within that average Impact of higher air and soil temperature on water availability, and consequently on NPP for different soil and vegetation types Impact of climate change (including extremes in temperature, rainfall, and wind) on soil hydrological conditions, (dis)aggregation, drying, erosion, and SOC leaching.

Models that incorporate the many complex processes occurring within the terrestrial ecosystems and their interaction with climate on multiple spatial and temporal scales will be needed to accurately assess the nature of climate
ecosystem coupling, the impact of climate change on the current terrestrial carbon inventory, and the carbon storage potential of the options described in the following section. Longterm ecosystem-scale observations and experiments will be required in order to improve understanding and validate the simulation models, with a particular focus on tropical ecosystems in view of their major contribution to carbon inventories and fluxes and the current lack of experimental data on ecosystem
climate interactions in this region. Some areas of current research are covered in the discussion of specific options below and in Section 21.5.

21.3

Terrestrial carbon storage options

The development and eventual deployment of approaches to increase terrestrial carbon storage follows a similar methodology to the RD&D process in other technology areas. Identified approaches are initially subject to site testing to understand the effects on carbon stocks and fluxes at a site scale. The evaluation of these trials

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Table 21.4 Approaches to increasing soil carbon stocks Terrestrial carbon storage strategy

Tactical approaches

Conservation agriculture

Minimal soil disturbance Permanent soil cover Crop rotations and associations, including agroforestry Reclaiming degraded land to reestablish soil C pools Afforestation and reforestation; reducing forest degradation and deforestation Reinstatement of wetlands, particularly coastal systems Use of high-yield crops Perennial planting, undercrops Managed fertilization Extend lifetime of wood products Recycling of wood products Use of biomass in zero-emission power generation Carbonization of biomass residues as stable biochar (see Glossary) Genetic manipulation of plants to increase belowground carbon allocation and recalcitrant carbon production Modifying soil chemistry to maximize belowground allocation Use of soil amendments to maximize SOC physicochemical protection Manipulation of microbial genetics to maximize biological protection of SOC and production of biochemically recalcitrant microbial compounds

Changing land use to ecosystems that sustain higher soil carbon stocks

Increasing NPP for any land use

Minimize and delay the return of carbon in plant products to the atmosphere

Increasing the fraction of NPP that finds its way into soil

Manipulating soil processes to maximize carbon retention in slow and passive C pools

also needs to consider other actual or potential environmental impacts in order to achieve full accounting for stocks and fluxes of carbon, as well as other GHGs. Mathematical models are developed and validated by field trial results, allowing sensitivity analyses to be performed over a wide range of site types and conditions. Table 21.4 summarizes the range of approaches that may be taken with the aim of increasing carbon storage in terrestrial ecosystems, including products derived from them.

21.3.1 Agricultural carbon storage Agricultural practices can make a significant contribution to carbon storage, at low cost, by increasing the soil carbon pool and reducing GHG emissions resulting from

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Carbon Capture and Storage

soil biochemical processes (CO2, N2O, CH4), as well as by producing biomass as an energy feedstock, offsetting fossil fuel use. Agricultural carbon storage, or “carbon farming,” refers to the suite of practices for managing vegetation and soils in agroecosystems with the additional aim, alongside agricultural production, of increasing carbon stocks in these ecosystems and/or lowering the net rate of release of CO2 or other GHGs to the atmosphere. During the December 2015 COP21 meeting in Paris, the “4 per 1000” initiative was launched by the French Ministry of Agriculture, with the aim to increase the global soil carbon inventory by 0.4%/year through agricultural, agroforestry, and other land-management practices. Considering the B700 Gt-C inventory in the top 30 cm of soils as the target for such practices, this would represent an additional sink of B3 Gt-C/year, and recent estimates of SOC sequestration potential suggest that this is technically feasible (see Lal et al., 2015). Increasing the amount of crop residue available to be converted into humus can move long-term soil carbon stocks to a higher equilibrium level over a decadal timescale. Intensified cropping and conservation tillage (CT) are examples of agricultural practices that increase this availability. Biologically altered organic inputs, such as manure, can result in greater sustainable increases in SOC due to the inclusion of material that decomposes less rapidly than unaltered crop residues. These practices—reduced tillage, crop residue retention, increased carbon inputs—also result in increased levels of microbial biomass and retention in soils of MOM, further increasing soil carbon content. When an agricultural practice such as conservative tilling is put in place, the soil carbon content will increase until the adsorptive capacity of the soil is saturated and a new equilibrium is reached. The additional carbon inventory will remain in the soil while the practice is continued, but will be released within a few years and the previous equilibrium reestablished if the practice is discontinued.

Conservation agriculture Conservation agriculture (CA) comprises a suite of practices that aim to sustain crop yields by improving soils and crop environments. As discussed in this section, several of these practices also have the potential to increase carbon storage in soils, although these benefits are still actively debated.

Conservation tillage Tilling breaks down the aggregated structure of the soil, both at the macroaggregate level by physical action and at the microaggregate level by subsequent dehydration of binding clays. This allows previously protected labile SOM to be exposed to microbial decay and to loss by wind and water erosion. The net effect of this loss of SOM may be mitigated if the eroded material is deposited in downstream sediments, particularly if these are protected from decomposition. The interlinked processes of erosion and deposition and their impact on net carbon stocks are poorly understood and are the subject of ongoing research.

Storage in terrestrial ecosystems

557

Soil disturbance through tillage has a significant impact on the activity and makeup of the microbial community, with a reduction in tillage intensity resulting in increases in: G

G

G

G

Fungal to bacterial biomass ratio Mycorrhizal colonization Total soil carbon and nitrogen content Macroaggregated soil structure

Natural ecosystems have fungal-dominated microbial communities and are able to sustain the decomposition of organic material and recycling of nutrients without the supplementary inputs required in intensively managed agroecosystems. By avoiding the interruption of nutrient-recycling processes and maintaining the waterholding capacity of soils, practices that reduce soil disturbance therefore minimize the need for increased fertilization and irrigation to sustain soil productivity and soil carbon stocks. CT has the primary aim of reducing soil erosion and is defined by the IPCC as any tillage and planting method in which 30% or more of the crop residue remains on the soil after harvesting. These methods, which include no till, ridge till, minimum till, and mulch till as well as drill planting, minimize the disturbance of the soil and may allow SOC to increase to a higher equilibrium level. Crop residues either remain on the surface in the case of no tillage or are partially incorporated into the soil surface layer for other CT practices. The change to CT can increase SOC stocks by 0.1
0.5 t-C/ha-year depending on the soil type and typically requires a 10- to 50-year period to reach a new equilibrium. Reversion to previous intensive tillage practice would result in a return to the previous SOC equilibrium levels, but over a shorter period. The impact of no till on aggregates is significantly reduced in northern regions, since winter frosts cause a natural turnover of soil aggregates. Current research in tilling practice includes: G

G

Impact of tilling practices on microbial biomass and SOC and nitrogen under various crops Relative importance of the degree of soil disturbance, soil moisture content, and crop residue placement on fungal to bacterial biomass ratios under reduced or no tillage

Crop selection, rotation, and intensified cropping The amount of crop residue available to be converted into humus can be increased by a number of practices that intensify cropping, such as: G

G

G

G

Elimination of fallow periods in seasonally cold or dry environments Selection of crop varieties for high yield of aboveground and belowground biomass Selection, breeding, or genetic manipulation of crops for increased production of recalcitrant material, primarily lignin Application of fertilizers and other additives to increase crop biomass

Intensified cropping increases the amount of aboveground biomass available to contribute to SOC and also increases belowground input to SOC through root and

558

Carbon Capture and Storage

microbial biomass. The resulting increased availability of aboveground organic inputs will have maximum impact on SOC when applied in conjunction with CT. Roots tend to decompose more slowly than leaf litter, possibly as a result of the higher proportion of complex organic compounds in roots that are more slowly transformed and therefore contribute to a longer SOC residence time. Selection, breeding, or genetic manipulation of crop varieties that result in higher belowground NPP allocation can therefore contribute to increasing soil carbon stocks. The establishment of perennial vegetation as a biomass crop, on previously tilled croplands, combines the advantages of intensified cropping and no tillage with the added advantage that fossil fuel use can be offset through biomass conversion. Assessment of the impact of such crops on carbon storage in soils is important in order to fully evaluate the carbon impact of bioenergy crops and is an ongoing research area. Agroforestry systems, which integrate tree planting with agricultural practices (e.g., alley cropping, under-cropping, windbreaks), combine the potential of forests to increase biomass production and soil carbon storage while maintaining an agricultural production system. Current research in crop selection, rotation, and intensified cropping includes: G

G

G

G

G

Understanding the genetic controls of aboveground versus belowground biomass production Understanding the impact of cover cropping and other organic farming practices on soil microbial communities and MOM Understanding how the plant
microbe interactions in the rhizosphere influence SOC inventory and longevity Controlling plant
microbe interactions in the rhizosphere to maximize carbon storage, through plant breeding or transgenic plant development Understanding the influence of various crops, including bioenergy crops, on soil carbon stocks for varying climatic conditions and soil types.

Managing soil biogeochemistry The SOC pool is susceptible to the chemical conditions in the soil, and modification of soil chemistry can be used to influence the rate of accumulation or decomposition of humic material, as well as the redistribution of organic carbon into deeper subsurface layers. Sorption of organic molecules onto mineral surfaces protects these humic fragments from further mineralization and is aided by the presence in the soil of polyvalent cations. Addition of lime (CaO) or minerals containing iron and manganese oxides provides a source of these cations and can result in an increase in the sorption and protection of organic carbon. However, the shift in pH due to lime addition may also promote microbial decomposition of SOM. Organic carbon remains susceptible to continued mineralization in the upper soil layers, particularly in the rhizosphere, where respiratory activity is high. Soil carbon can therefore be increased by processes that move organic carbon from the upper soil layers into deeper, less oxidative layers. Adsorbed organic carbon can be

Storage in terrestrial ecosystems

559

released into pore water by the addition of anions such as phosphate or sulfate that will compete for sorption sites on mineral surfaces. Under suitable hydrological conditions, vertical pore water flows can then carry dissolved organic carbon to deeper soil layers, where it can be adsorbed onto unsaturated mineral surfaces. As well as the primary aim of plant nutrition, fertilizer addition can thus be managed to achieve the additional objective of transporting carbon deeper into soils, increasing total soil carbon stocks.

Biochar Biochar, the by-product of biomass pyrolysis for bioenergy production, has been widely studied and applied as a soil amendment that influences a wide range of soil properties, including increased nutrient and water retention capacity, resulting in improved soil fertility. Depending on the pyrolysis temperature and precursor material, a large proportion ( . 90%) of the carbon is resistant to microbial activity and its addition therefore augments the passive carbon pool in soils. Positive priming effects, resulting in a short-term loss in SOM, have also been observed after the addition of biochar resulting from the low-temperature pyrolysis of non-woody biomass. The possibility of using biochar application to soil as a carbon sequestration measure was first proposed by Lehmann et al. (2006), who estimated that if expected bioenergy supply in 2100 was provided by pyrolysis, returning the resulting biochar to the soil would result in sequestration of 5
10 Gt-C/year with a potential sink in the order of 400 Gt-C in global croplands and temperate grasslands. Recent research in this area, investigating the potential for distributed smallto medium-scale biomass pyrolysis plants to provide local heat and power while producing biochar for carbon storage, has been reported by Pro¨ll et al. (2017). Biochar addition has also been shown—under applicable circumstances—to have wide ranging impacts on soil processes, including reducing the emission of GHGs (CH4, NO2), the removal of pathogens and growth inhibiting compounds, and various impacts on microbiome abundance and community structures. The circumstances under which these effects occur, and their influence on biochar addition as a carbon sequestration measure, is an active area of research.

Soil biogeochemistry R&D Current research in soil biogeochemistry for carbon storage includes: G

G

G

G

G

G

G

Understanding the processes that control the accumulation, movement, distribution, and residence of carbon in the vertical soil profile (e.g., impact of soil mineralogy, soil chemistry, and plant carbon input quality on SOC storage and residence time) Understanding the spatial and temporal variability of these processes Development of methods to assess the carbon storage potential of soils Understanding how soil aggregation, pore network properties, and aggregate stability affect SOC capacity and microbial activity Impact of climate change on soil respiration and carbon turnover Impact of biochar addition on soil biogeochemical processes, including the effects of precursor biomass, pyrolysis conditions, and receiving soil type Optimal biochar characteristics to maximum soil function and carbon sequestration benefits under specific soil and climate conditions

560

Carbon Capture and Storage

Manipulation of microbial communities As noted above, soil microbial communities facilitate some of the key biochemical processes that determine the fate of SOC as well as the emissions of GHGs such as N2O and CH4. These processes include decomposition of animal and microbial biomass and the resulting supply of metabolites to soil organisms; mobilization of plant nutrients such as iron and phosphorus; nitrogen cycling, including fixation and denitrification; and metabolic removal of soil contaminants. While the biochemistry of these processes is increasingly known, their sensitivity to microbial community composition and dynamics is less well understood. Due to their different physiologies, the two main microbial groups interact differently with soil properties and processes so that community composition and activity has an impact on soil carbon cycling and storage. Bacterial respiration mineralizes B60% of the fixed organic carbon metabolized from decaying plant material, while fungi respire only 30%
40%, which translates to a higher microbial growth efficiency, expressed as the weight fraction of metabolized carbon that is incorporated into microbial biomass and by-products. A shift in the microbial community toward fungal dominance would therefore increase SOM by reducing the loss through respiration and increasing MOM. This shift toward a higher fungal to bacterial biomass ratio is one factor that could increase SOM under no-till cultivation, since tillage interrupts fungal growth by breaking up the network of fungal mycelia. Since the incorporation of SOM into macroaggregates provides physical protection, the enhanced stability of aggregates in fungal-dominated soils reduces carbon mineralization by reducing bioavailability, leading to increased soil carbon accumulation. A better understanding of these processes would open up the possibility of modification by direct or indirect means in order to maximize carbon storage and minimize GHG emissions. Direct methods could potentially include genetic engineering of microbial genes that control or modify specific functions, while indirect means would include altering soil chemistry and pH in order to enhance existing functions. The complexity of microbial communities involved in biochemical soil processes provides the opportunity to use the population dynamics of these diverse communities as indicators of the varying status of soil—for example, as indicators of nutrient availability or SOC content. Research studies using DNA sequencing techniques have confirmed correlations between soil status indicators, such as SOC, and the relative abundance of different microbial species, which respond differently to changing soil conditions. Current research areas in microbial processes in soils include: G

G

G

Understanding fungal and bacterial contributions to the decay pathways from above- and belowground plant residues to stable humified SOC Identification of microbial species or groups that play a part in maximizing SOC Understanding how microbial activity can be shifted toward increased SOC longevity for varying soil types and chemistry, and for different plant residue types

Storage in terrestrial ecosystems

G

G

G

G

561

Understanding the relative importance of soil disturbance, soil moisture, and residue placement on microbial community structure and microbial biomass Understanding the relative influence of biochemical recalcitrance, physical protection in aggregates, and chemical protection by clay association in controlling the fate of fungal and bacterial MOM and their relative contribution to soil carbon stocks Understanding the role of soil animals in carbon decomposition and transport Understanding how elevated [CO2] and climate change affect microbial communities and soil processes.

21.3.2 Changes in land use Strategies to increase the terrestrial organic carbon stocks through changes in land use typically involve the conversion of lands to uses that reduce soil disturbance and maximize the content and longevity of organic carbon. Land uses may be ordered in terms of their effective contribution to terrestrial carbon stocks, as shown in Table 21.5. The terrestrial carbon stock can therefore be increased by any change in land use that moves up the scale, for example, the restoration of degraded land to any other use, the conversion of croplands to pasture or wetlands, or afforestation of any land type.

Wetland management and restoration Wetlands, including estuaries, mangrove forests, marshes, peatlands, and northern tundra, cover 7% of the earth’s surface and, aside from those in cold climates, are some of the most productive of terrestrial ecosystems, contributing an estimated 10% of primary production. These areas accumulate large stocks of belowground organic carbon, and therefore present an opportunity to increase terrestrial carbon Table 21.5 Relative contributions to carbon stocks of different land uses Contribution to terrestrial carbon stocks

Land type

Comment

High

Forest

High productivity, longevity, unfavorable decomposition conditions (boreal forests), and minimal soil disturbance No soil disturbance No soil disturbance Reduced soil disturbance, bio-modified carbon input Frequent soil disturbance Low-existing carbon stock

Wetlands Grasslands Pasture

Low

Croplands Degraded land

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Carbon Capture and Storage

storage both by protecting and enhancing existing wetlands as well as by restoring those that have been degraded. Northern peatlands, for example, are estimated to have accumulated 300
450 Gt-C since the end of the last glacial period—equal to 50%
70% of the carbon currently present in the atmosphere. The restoration of tidal salt marshes is estimated to achieve an SOC accumulation rate in the order of 2 t-C/ha-year, similar to low-grade forest growth, while algal productivity in these ecosystems can add a similar amount. Depending on the type of plant material and the degree of inundation, carbon stored in these types of wetland can have a residence time of decades to millennia due to the very slow rate of decomposition under anoxic conditions and, in northern peatlands, for example, also under low temperatures. Draining of wetlands for uses such as agriculture, forestry, or urban and industrial development results in a loss of organic material due to an increase in aerobic microbial decomposition, with the consequent release of CO2 to the atmosphere. Reestablishment of wetlands requires a restoration of previous hydrological flows by removing or plugging drainage systems or by artificially diverting water flows. Attempts to restore wetlands have shown that the loss of SOC is not easily reversed, with created wetland SOC being slow to accumulate, pointing to complexities in the overall ecosystem that are difficult to recreate. In freshwater environments the increased carbon stock will be offset by an increase in the emission of methane released through decomposition if the new water table is close to the surface. This is not an issue for coastal wetlands such as tidal salt marshes, since methane emissions are not significant in a saline environment. The carbon resource present in coastal vegetated ecosystems such as mangrove forests, tidal salt marshes, and seagrass meadows—collectively termed “blue carbon”—is one area of wetland management that has received increasing attention since the issue in 2009 of the UNEP report Blue Carbon. A Rapid Response Assessment (see Resources). Collectively, these ecosystems are estimated to contribute 50%
70% of the carbon deposited annually in deep ocean sediments, and their preservation and restoration is therefore of importance in preserving and enhancing this carbon inventory. Current RD&D efforts in wetland management and restoration are summarized in Table 21.6.

Forestry management, afforestation, and reforestation The carbon stocks in forests can be enhanced by reducing logging and deforestation, for example, by the protection particularly of old-growth forests, by the regeneration of secondary and degraded forests with standing biomass and SOC below their potential values, and by the application of specific silvicultural practices. Afforestation of croplands can increase carbon stocks by 1
10 t-C/ha-year over periods of 50
100 years, while improvements in management practices in existing forests can contribute 1
2 t-C/ha-year over a period of 10
20 years.

Storage in terrestrial ecosystems

563

Table 21.6 RD&D efforts in wetland management and restoration RD&D area

Description

Quantifying existing carbon stocks and fluxes

Quantifying stocks and fluxes by wetland type to enable estimates of carbon storage potential Dynamics of carbon cycling in coastal wetlands and response to sea-level changes Full accounting for climate forcing of wetlands (CH4, N2O, albedo, water vapor) Evaluation of current wetland management and restoration practices to assess their impact on carbon storage Identification and development of new wetland-restoration approaches to ensure that created wetlands mimic natural wetlands Impact of nutrients on primary production and decomposition rates in wetland systems Assessing the degree to which existing wetland carbon stocks are vulnerable to human activity and climate change Identifying and developing wetland-management practices and technologies to reduce loss of carbon from northern latitude wetlands Construction and verification of integrated ecosystem
climate
hydrological models to gain quantitative insights into the relationships between wetland environmental factors and soil carbon storage potential Methods to assess net carbon uptake and monitor methane and CO2 fluxes, particularly if the degree of inundation varies due to changing hydrological fluxes or climatic conditions

Wetland-management practices

Wetland vulnerability

Wetland ecosystem process modeling

Monitoring and verification techniques

Forestry management practices Carbon stocks in standing forest biomass and in forest soils can also be maximized through specific management practices, including the optimization of harvesting schedules, forest fertilization, and the application of low-impact logging methods. The timing and quantity of timber extracted from commercial forests during thinning and harvesting, whether through selective- or clear-felling, are traditionally driven by the end product requirements, with the aim of maximizing commercial returns. If carbon storage is also included as an objective, the optimal harvesting strategy shifts toward selective harvesting with a minimum cutting diameter as well as longer rotation cycles, although the latter also increases the risk of carbon loss through major disturbances such as fires, windthrow, and insect outbreak. Forest fertilization by the addition of nitrogen, typically as ammonium nitrate (NH4NO3), is practiced in many commercial forestry operations worldwide with the aim of increasing the biomass in stem and branches. Fertilization is most beneficial

564

Carbon Capture and Storage

on low- to medium-grade sites, where nutrition is the limiting factor for growth. The incremental carbon storage rate depends on many factors including tree species, climate, and fertilization dosage and timing, with various investigations indicating carbon storage rates in the range of 0.2
0.8 t-C/ha-year can be achieved for periods of 10
20 years. Studies have shown that nitrogen addition can also aid in retaining SOC by reducing microbial activity and the attendant respiration of CO2 from the soil. Clearly a tree will allocate NPP to root production and root exudates only if this is necessary to build the root networks and sustain the microbial activity needed to deliver nutrients and water to the plant. If nutrients are more readily available, for example, as a result of fertilization, belowground allocation will be reduced and with it the attendant root and microbial respiration. While higher nitrogen levels have been shown to suppress SOC mineralization, whether this aids in carbon storage will depend on the balance between the reduced decomposition of existing SOC and the reduced input from new root and microbial biomass. Low-impact logging aims to minimize the disturbance of forest soil during logging while ensuring that the remaining trees, new trees, and other vegetation retain maximum potential for growth and carbon storage. Particularly in tropical rainforests, clear-felling results in substantial carbon emissions as a result of soil erosion and subsequent decomposition of SOC. An evaluation of the net carbon storage resulting from forest management, including forest fertilization, must also account for the carbon fluxes resulting from other practices such as fire management. While fires have an important role in rejuvenating forest and grassland ecosystems, in semi-arid areas or under drought conditions, fires pose a significant risk to carbon storage in standing forest biomass. Appropriate fire-management practices may include mechanical removal of undergrowth and controlled fires, depending on the specific conditions. The carbon flux resulting from fire-management practices must be accounted for when evaluating the net carbon storage in existing or reestablished forests.

Afforestation and reforestation Afforestation of agricultural or other non-forested lands, as well as increasing the peripheral tree cover on crop or pasture lands or in urban areas, is currently considered to be the largest potential contributor to the increased storage of carbon in the terrestrial ecosystem. Within wetland ecosystems, restoration of hardwood forests in bottomland (floodplains and marshes) is a storage approach that combines the high primary productivity of wetlands with the slow release of SOC under flooded conditions. Other practices, such as the planting of trees as riparian buffer zones along streams or as windbreaks, and the planting of cover crops below trees, can also sustain the SOC stocks by preventing soil disturbance and erosion. Agroforestry, noted above as a component of CA, is one such option, where trees or shrubs are intercropped with grains, vegetables, or forages in multi-storey or silvopastoral cropping systems.

Storage in terrestrial ecosystems

565

The longevity of the carbon stocks established through afforestation can be extended by increasing the demand for longer-lasting wood products and also by maximizing the lifetime of wood products, for example, through recycling. As well as the storage of carbon in standing and harvested timber, afforestation can also lead to increased SOC as a result of reduced soil disturbance and increased abundance and diversity in the fungal community, both of which enhance soil micro- and macroaggregation and SOC protection. Afforestation on a continental scale has also been proposed by Ornstein et al. (2009) as a geoengineering solution to climate change. Irrigated afforestation of the Sahara desert and Australian outback, together covering B1.5 3 109 ha, could potentially capture and store 10
15 Gt-C/year, well in excess of current anthropogenic emissions. Some 500 mm/year of irrigation would initially be required (5 3 1012 m3/year for the Sahara) but, as the forest becomes established, this requirement reduces due to a biogeophysical feedback which links evapotranspiration, condensation, and latent heat release with an increase in rainfall. Afforestation on this scale could also have a variety of unintended consequences, such as an impact on Atlantic hurricane seeding and on El Nin˜o events, a reduction in ocean fertilization by wind-blown dust (see Section 20.5.1), and potentially enabling the spread of infectious diseases, as well as being at high risk of destruction by fires and locust swarms. On a smaller scale, afforestation of otherwise unproductive land in arid coastal areas, irrigated by desalinated seawater (using solar power or biomass derived from the plantation), is a carbon farming opportunity that has received considerable attention. Trees and shrubs that are well adapted to arid environments, including biofuel crops such as Jatropha curcas (Jatropha) and Simmondsia chinensis (Jojoba), could store B5 t-C/ha-year, and detailed simulation studies have shown that the feedback resulting in an increase in rain and dew fall could be effective over plantations as small as 104 km2. A significant carbon price will also encourage landowners to establish carbon forestry on land which could otherwise be used for agricultural purposes. In such a case, afforestation would lock the landowner into an uncertain carbon price over a period of 50
100 years and would preclude any change of crops to take advantage of short-term price variations. This loss of optionality may be a significant disincentive.

21.4

Full GHG accounting for terrestrial storage

While the various land-use and land-management approaches described above have the potential to enhance carbon storage in terrestrial ecosystems, a wide range of indirect effects need to be considered in arriving at a comprehensive assessment of the net impact on the fluxes of CO2 and other GHGs. Agriculture is a major contributor to the flux of both nitrous oxide (N2O) and CH4 to the atmosphere, both of which have significantly higher global warming potential over a 100-year timescale than CO2 (GWP100yr 5 23 and 296, respectively).

566

Carbon Capture and Storage

Microbial activity is responsible for the major loss of nitrogen from the soil, as N2 and N2O, and changes in land use and practices that affect microbial communities, whether directly or indirectly, will affect these emissions. Practices such as tillage, quantity and timing of application of nitrogen fertilizers, and drainage conditions will all have an impact on the rate of nitrogen loss from soils. Methane is emitted from soils under highly reducing conditions such as occur in freshwater wetlands and other flooded soils. Wetland restoration or irrigation practices that dramatically change the oxidation status of soils, such as periodic flooding, will therefore tend to increase CH4 emissions. Coastal wetlands are an exception, as noted above, since CH4 emissions are negligible from saline environments. Forests also have indirect climate impacts as a result of their low albedo and high water vapor input to the atmosphere. Typically the albedo of forests is 30%
70% of the albedo of grasslands, for coniferous and deciduous forests, respectively, while the evaporative loss from a forest with a high leaf area index can exceed that from a water surface. Other more remote GHG impacts from changes in land-use or land-management practices can arise from fossil fuel consumption for the production, transport, and use of agricultural machinery and other inputs such as fertilizers, mineral additives, and biocides. Monitoring and verification of the residence time of incremental stocks is also required for terrestrial carbon to be admissible for trading; aboveground stocks can be affected by fires and other causes of mortality, and SOC may be lost through unexpected, possibly site-specific, feedbacks, or by a reversion to historical practices.

21.5

R&D in terrestrial carbon storage

Carbon storage in terrestrial ecosystems is a relatively new R&D area, although a number of programs have been established in the last decade. The initial aim of these programs is to improve our understanding of the fundamental physical, chemical, and biological processes that control the accumulation and fate of carbon stocks, to develop measurement and manipulation techniques that allow those processes to be quantified, and to develop verifiable models of those processes to allow extrapolation of experimental results to a landscape scale or to other environmental conditions. The development and demonstration of specific strategies to enhance carbon storage in terrestrial ecosystems awaits the outcome of these fundamental investigations, of which two examples are described in the following sections.

21.5.1 Free air CO2 enhancement experiments FACE experiments are an important class of midscale experiments that investigate the carbon cycle in a variety of terrestrial ecosystems, with emphasis on the impact

Storage in terrestrial ecosystems

567

Figure 21.8 Aspen (Rhinelander) FACE experimental configuration. Source: Courtesy, Michigan Technological University. Photo Credit, David F. Karnosky.

of elevated [CO2] (eCO2) and in some cases also elevated ozone concentration (eO3). A typical FACE facility consists of a number of plots within which the trace gas concentration is maintained at an elevated level during the daylight hours of photosynthetic activity. The Aspen (Rhinelander) FACE, operated by the Brookhaven National Laboratory and the Michigan Technological University between 1997 and 2009, was a typical forest ecosystem example. The layout of this facility, shown in Figure 21.8, consisted of 12 circular experimental plots, each 30 m in diameter, within which [CO2] and [O3] can be controlled. The trace gases were introduced from a set of vertical vent pipes positioned on the circumference of each plot, with gas being vented only from those pipes upwind of the plot. The effect of eCO2 was investigated by introducing an excess [CO2] of B200 ppm or B50% above ambient concentration. Sensors mounted within the canopy provided feedback to a computer control system that maintained the trace gas concentration at the desired level, and the system was typically able to maintain the annual average [CO2] within 610% of the target level for . 90% of the canopy volume within each experimental plot, although short-term excursions from the target level were larger. Since the plots were unconfined, other aspects of the natural environment remained unchanged. The design allowed assessment of the effects of these gases, either alone or in combination, on many attributes of the ecosystem, including above- and belowground growth and soil carbon. FACE experiments have been constructed in a range of ecosystems, from forests to desert scrub, and the main features of a number of these experiments are summarized in Tables 21.7 and 21.8. Despite the importance of understanding climate feedback effects in these ecosystems and their potential significance for terrestrial carbon storage, many of the experiments listed have been closed since the table was originally compiled, often as a result of competing funding priorities rather than the completion of their respective scientific programs; others continue on a monitoring

Table 21.7 FACE experiments in forest ecosystems FACE facility

Organization

Location

Ecosystem

Species

Key parameters

Harshaw Experimental Forest, Rhinelander, WI

Temperate deciduous forest

9 FACE 1 3 control, [CO2] 5 560 ppm, [O3] 5 1.5 3 ambient

Henfaes Experimental Farm, Bangor, UK

Temperate deciduous forest

Aspen (Populus tremuloides) Birch (Betula pendula) Sugar Maple (Acer saccharum) Birch (Betula pendula)Alder (Alnus glutinosa)Beech (Fagus sylvatica) Loblolly pine (Pinus taeda)

First-generation experiments

Bangor FACE

Brookhaven National Laboratory, Michigan Technological University University of Wales

Duke Forest FACE

Brookhaven National Laboratory

Duke Forest, Orange County, NC

Temperate pine forest

Euro FACE

University of Tuscia

Tuscania, Viterbo, Italy

Temperate deciduous forest

ORNL-FACE

Oak Ridge National Laboratory

Oak Ridge National Environmental Research Park, Oak Ridge, TN

Temperate deciduous forest

Aspen (Rhinelander) FACE

White Poplar (Populus alba) Black Poplar (Populus nigra) Eastern Cottonwood (Populus deltoides), and hybrids American Sweetgum (Liquidambar styraciflua)

4 FACE 1 4 control, 8 m diameter rings, [CO2] 5 1 200 ppm 4 FACE 1 8 control, 30 m diameter rings, [CO2] 5 ambient 1 200 ppm 3 FACE 1 3 control, 22 m diameter rings, [CO2] 5 380, 200 ppm 2 FACE 1 3 control, 25 m diameter rings, [CO2] 5 565 ppm

Second-generation experiments—mature forests AmazonFACE

Manaus, Brazil Universidade Estadual Paulista, Brazil and Oak Ridge National Laboratory, USA

Old growth tropical rain forest

Diverse (52 tree species across .200 years, 30 m canopy, pilot the 2 pilot plots) phase: 1 FACE 1 1 control, 30 m plots, later 3 1 3 additional plots, [CO2] 5 1200 ppm, eCO2 start Dec 2016

BIFor-FACE

The Birmingham Institute of Forest Research, University of Birmingham

Staffordshire, United Kingdom

Temperate deciduous forest

EucFACE

Hawkesbury Institute for the Environment, Western Sydney University Lund University, Linnaeus University, and Gothenburg University

Richmond, NSW, Australia

Subtropical dry forest

Oak (Quercus robur), Sycamore (Acer pseudoplatanus), Silver birch (Betula pendula), with hazel coppice (Corylus avellana) understorey Eucalyptus (Eucalyptus tereticornis)

Asa Research Park, Sma˚land, Sweden

Boreal pine forest

Scots pine (Pinus sylvestris)

SwedFACE

B150 years, 25 m canopy, 9 3 28 m plots, [CO2] 5 1150 ppm, eCO2 start April 2016

.100 years, 22 m canopy; 3 FACE 1 3 control, 25 m plots, [CO2] 5 1150 ppm, eCO2 start Sept 2012 34 yr, 12
15 m canopy, 6x25 m plots, [CO2] 5 1150ppm coupled with nutrient (P, N) treatment, eCO2 planned Apr 2017

Table 21.8 FACE experiments in non-forest ecosystems FACE facility

Organization

Location

Ecosystem

Species

Key parameters

AG FACE

Grains R&D Corporation and the University of Melbourne

Agroecosystem

Wheat (Triticum spp.)

8 FACE 1 8 control, [CO2] 5 350, 550 ppm, site 1: 12 m diameter rings, site 2: 4 m diameter rings

Arizona FACE

University of Arizona

First site; Horsham, Victoria, AustraliaSecond site; Walpeup, Victoria, Australia Maricopa Agriculture Centre, Maricopa, AZ

Agroecosystem

4 FACE 1 4 control, [CO2] 5 1200 ppm

BioCON FACE

University of Minnesota

Cedar Creek Ecoscience Reserve, Minneapolis, MN

Grassland

GiFACE

University of Gießen

Gießen, Germany

Temperate grassland

Nevada Desert FACE

Brookhaven National Laboratory, University of Nevada CSIRO and James Cook University

Mojave Desert, Mercury, NV

Desert scrub

Cotton (Gossypium hirsutum)Wheat (Triticum spp.)Sorghum (Sorghum spp.) 16 species in 4 groups; warm-season grasses (C4), cool-season grasses (C3), forbs, and nitrogen-fixing legumes Diverse grass species (including Oat grass Arrhenatheretum elatioris), non-leguminous herbs and legumes Creosote Bush (Larrea tridentata), Bur-sage (Ambrosia dumosa)

Yabulu Refinery, Townsville, Queensland, Australia Urbana-Champaign, IL

Coastal tropical savannah

Kangaroo Grass (Themeda triandra), Eucalyptus, and Acacia

4 FACE 1 2 control, 15 m diameter rings, [CO2] 5 370, 460, 550 ppm

Agroecosystem

Soy (Glycine max): 16 rings under elevated [CO2] and [O3]; Maize (Zea mays): 8 rings under elevated [CO2]

16 FACE 1 8 control, 15 m diameter rings, [CO2] 5 550 ppm, [O3] 5 1.2 3 ambient

Oz FACE

Soy FACE

University of Illinois

3 FACE 1 3 control, 20 m diameter rings, each with B60 2 m 3 2 m plots, [CO2] 5 368, 56 ppm 3 FACE 1 3 control, 8 m diameter rings, [CO2] 5 120% 3 FACE 1 6 control, 23 m diameter rings, [CO2] 5 ambient 1 50%

Storage in terrestrial ecosystems

571

only basis, without CO2 enhancement. Largely for logistical reasons, the first generation of forest FACE experiments focused on young trees in temperate environments (including some species from boreal forests), while second-generation experiments expand this coverage to mature forests in (hemi)boreal forests and tropical rainforests, which is important since the latter ecosystem accounts for over 2/3 of live terrestrial plant biomass. Full details of individual projects can be found on the respective web sites, listed below. Ecosystem-scale experiments of this type allow a wide range of questions relating to terrestrial carbon storage to be investigated, some of the main research topics being as follows: G

G

G

G

G

Evaluating the sinks and sources of CO2 in terrestrial ecosystems to determine the limits of and constraints (e.g., nutrient (N and P) availability, periodic drought stress) on natural carbon storage potential Understanding the processes that control CO2 fluxes between the atmosphere and terrestrial ecosystems from molecular to landscape scales Understanding the biogeochemical processes, conditions, and interactions (on cellular, individual plant, community, site, and landscape scales) that control the rate of storage and the longevity of SOC (e.g., quantifying the impact of belowground processes and nutrient feedbacks; genetic and environmental controls on aboveand belowground allocation; processes that affect the longevity of NPP allocated belowground) Understanding the influence of climatic and other feedback mechanisms, including the interaction between increasing [CO2], mean temperature and water availability, on biogeochemical cycles, microbial communities, etc. Developing conceptual and mathematical models of these processes to allow extrapolation over longer timescales and differing environmental conditions

In addition, the extension of these experiments to mature forests will help to clarify whether increased growth observed in young trees under eCO2 represents simply an acceleration of growth (potentially with no impact on final C storage) or a change to a higher equilibrium biomass at maturity, as illustrated in Figure 21.9. The curves show schematically the accumulation of biomass with time since establishment, with two FACE experimental periods shown by the gray-shaded areas. In the first FACE period, representing a young forest experiment, an increase in biomass accumulation rate is observed, whether or not the final equilibrium is affected by eCO2 or is determined by other pre-existing constraints such as light or nutrient availability. In the second FACE period, representing a mature forest experiment, any increase in observed accumulation rate must reflect a change to a higher equilibrium under the influence of eCO2. Results from the first generation of FACE experiments, which have been compiled in a number of review articles (see References), have improved our understanding of many of the processes listed above and contribute to the ongoing improvement in modeling of climate
ecosystem interactions and feedbacks. These experiments have consistently demonstrated that increased atmospheric [CO2] leads to an increase in NPP and water use efficiency (i.e., reduced water

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Carbon Capture and Storage

Total biomass (t-C/ha)

500 400

300

Growth to higher equilibrium

200 Accelerated growth to unchanged equilibrium

100 0

eCO2 period

eCO2 period

20 40 60 80 100 Years since stand establishment

120

Figure 21.9 Schematic forest biomass accumulation curves, showing potential impacts of eCO2.

transpired per unit of biomass growth). However, the implications for SOC have been less clear, with inconsistent or unexpected results demonstrating that the processes and feedbacks affecting SOC are even more complex than anticipated, and are influenced by a wide range of site-specific properties and histories.

21.5.2 CSiTE terrestrial sequestration R&D program The US Department of Energy-sponsored Consortium for Research on Enhancing Carbon Sequestration in Terrestrial Ecosystems (CSiTE) was established in 1999 as a multiinstitutional research effort involving the Argonne, Oak Ridge, and Pacific Northwest National Laboratories and a number of partnering universities. CSiTE aimed to address a number of research questions that are critical to protect stored carbon and enhance carbon accrual into terrestrial environments, namely: G

G

G

G

What are the physical, chemical, and biological processes controlling the input, distribution, and longevity of carbon in soils? How can these processes be exploited to enhance terrestrial carbon uptake? How do terrestrial carbon-storage strategies relate to and influence other approaches to climate change mitigation? What is the long-term potential for terrestrial carbon storage to materially affect climate change?

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573

Table 21.9 CSiTE R&D themes to enhance carbon storage in terrestrial ecosystems R&D theme

Main experimental objectives

Soil carbon inputs

Investigation of the differences and intra-annual variation in root production, mortality and decomposition, and root and microbial respiration for different switchgrass varieties and fertilization treatments Improved understanding of the ways in which soil structure controls the transformation of organic carbon inputs, through both biotic and abiotic humification processes, and subsequent stabilization as SOM Understand the influence of switchgrass varieties and crop-management practices on soil microbial community function and structure, and the impact of changes in these communities on soil carbon accrual and storage Understanding humification chemistry, including identification and optimization of the chemical factors that can be manipulated to enhance storage, and development of measurement techniques to rapidly assess whether carbon stocks are increasing or declining in a soil Evaluation of the processes that control the transport of solid- and solution-phase carbon through the soil profile and its accumulation in deep soils, including the influence of soil type, carbon inputs, and chemical effects resulting from fertilizers and additives to enhance soil surface humification

Soil structural controls

Microbial community function and dynamics

Humification chemistry

Carbon transport within soils

In the period up to 2006, the CSiTE collaboration undertook laboratory, field, and modeling studies in cropland, forest, and grassland ecosystems, which resulted in progress in a number of research areas (CSiTE, 2006), including: G

G

G

G

Understanding of factors controlling the mechanisms and rates of accumulation of SOM Development of new methods to investigate the role of microbial communities in soil carbon dynamics Identification of new manipulation concepts for enhancing soil carbon storage Development of improved modeling tools for soil processes

In 2007 a 5-year research program was started, focusing on the bioenergy crop switchgrass (Panicum virgatum), and with the overall objective of investigating sustainable biofuel production with accompanying enhancement of soil carbon stocks. The main objectives of the five experimental themes that made up this program are summarized in Table 21.9. The program also included the development of mechanistic models of soil carbon processes, building on the outcomes of the five experimental themes, in order

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Carbon Capture and Storage

to improve forecasting of soil carbon dynamics and enable an evaluation of the trade-offs and synergies between bioenergy crop production and enhancing soil carbon storage. Finally an integrated evaluation was planned, drawing on these experimental and modeling results to estimate the potential for enhancing soil carbon storage under bioenergy crops across the full range of soils, climatic conditions, and management practices at a national scale. This would allow an assessment of the economic competitiveness of dedicated bioenergy crops integrated with enhanced soil carbon storage as a GHG mitigation strategy. A number of papers reporting the final results from the program are included in References. Although this and many other research projects have resulted in a good understanding of the terrestrial carbon cycle and the many factors which influence it, as described in this chapter, it remains a challenge to determine the full carbon storage potential of terrestrial ecosystems, and to identify the factors that prevent some ecosystems from reaching that potential. The goal of establishing a set of clear management practices that serve to quantifiably maximize terrestrial carbon inventories is likely to remain illusive until these uncertainties are resolved.

21.6

References and resources

21.6.1 References Batjes, N.H., 1996. Total carbon and nitrogen in the soils of the world. Eur. J. Soil Sci. 47, 151
163. Becker, K., Wulfmeyer, V., Berger, T., Gebel, J., Mu¨nch, W., 2013. Carbon farming in hot, dry coastal areas: an option for climate change mitigation. Earth Syst. Dyn. 4, 237
251. Benemann, J.R., 1993. Utilization of carbon dioxide from fossil fuel burning power plant with biological systems. Energy Convers. Manage. 34, 999
1004. CSiTE, DoE Consortium for Research on Enhancing Carbon Sequestration in Terrestrial Ecosystems, 2006. Five Year Science Plan 2007
2011. Friedlingstein, P., et al., 2014. Uncertainties in CMIP5 climate projections due to carbon cycle feedbacks. J. Clim. 27, 511
526. Garcia-Franco, N., Martı´nez-Mena, M., Goberna, M., Albaladejo, J., 2015. Changes in soil aggregation and microbial community structure control carbon sequestration after afforestation of semiarid shrublands. Soil Biol. Biochem. 87, 110
121. Heimann, M., Reichstein, M., 2008. Terrestrial ecosystem carbon dynamics and climate feedbacks. Nature. 45, 289
292. Hofmockel, K.S., Zak, D.R., Moran, K.K., Jastrow, J.D., 2011. Changes in forest soil organic matter pools after a decade of elevated CO2 and O3. Soil Biol. Biochem. 43, 1518
1527. Hopkins, F.M., Filley, T.R., Gleixner, G., Lange, M., Top, S.M., Trumbore, S.E., 2014. Increased below ground carbon inputs and warming promote loss of soil organic carbon through complementary microbial responses. Soil Biol. Biochem. 76, 57
69. IPCC, 2000. Land Use, Land-Use Change and Forestry. Cambridge University Press, Cambridge, UK.

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Ja¨ger, H.-J., Schmidt, S.W., Kammann, C., Gru¨nhage, L., Mu¨ller, C., Hanewald, K., 2003. The University of Gießen free-air carbon dioxide enrichment study: description of the experimental site and of a new enrichment system. J. Appl. Botany. 77, 117
127. Jastrow, J.D., Miller, R.M., 1998. Soil aggregate stabilization and carbon sequestration: feedbacks through organomineral associations. In: Lal, R., Kimble, J.M., Follett, R.F., Stewart, B.A. (Eds.), Soil Processes and the Carbon Cycle. CRC Press, Boca Raton, FL. Jones, A.G., Scullion, J., Ostle, N., Levy, P.E., Gwynn-Jones, D., 2014. Completing the FACE of elevated CO2 research. Environ. Int. 73, 252
258. Kimble, J.M., Lal, R., Follett, R.F. (Eds.), 2002. Agricultural Practices and Policies for Carbon Sequestration in Soil. CRC Press, Boca Raton, FL. Lal, R., Negassa, W., Lorenz, K., 2015. Carbon sequestration in soil. Curr. Opin. Environ. Sustainability. 15, 79
86. Lehmann, J., Gaunt, J., Rondon, M., 2006. Bio-char sequestration in terrestrial ecosystems— a review. Mitig. Adapt. Strat. Global Change. 11, 403
427. Lehmann, J., Rillig, M.C., Thies, J., Masiello, C.A., Hockaday, W.C., Crowley, D., 2011. Biochar effects on soil biota—a review. Soil Biol. Biochem. 43, 1812
1836. Lorenz, K., Lal, R., 2006. Subsoil organic carbon pool. Encyclopedia of Soil Science. Taylor & Francis, Boca Raton, FL. Lorenz, K., Lal, R., 2014. Soil organic carbon sequestration in agroforestry systems—a review. Agron. Sustainable Dev. 34, 443
454. Medlyn, B.E., et al., 2015. Using ecosystem experiments to improve vegetation models. Nat. Clim. Change. 5, 528
534. Norby, R.J., et al., 2016. Model
data synthesis for the next generation of forest free air CO2 enrichment (FACE) experiments. New Phytol. 209, 17
28. Norby, R.J., Zak, D.R., 2011. Ecological lessons from free-air CO2 enrichment (FACE) experiments. Annu. Rev. Ecol. Evol. Syst. 42, 181
203. Ornstein, L., Aleinov, I., Rind, D., 2009. Irrigated afforestation of the Sahara and Australian outback to end global warming. Clim. Change. 97, 409
437. Peake, L., Freddo, A., Reid, B.J., 2014. Sustaining soils and mitigating climate change using biochar. In: De Las Heras, A. (Ed.), Sustainability Science and Technology: An Introduction. CRC Press, Boca Raton, FL. Post, W.M., et al., 2004. Enhancement of carbon sequestration in US soils. BioScience. 54, 895
908. Pro¨ll, T., Al Afif, R., Schaffer, S., Pfeifer, C., 2017. Reduced local emissions and long-term carbon storage through pyrolysis of agricultural waste and application of pyrolysis char for soil improvement. Energy Procedia. 114, 6057
6066. Rosenberg, N.J., Izaurralde, R.C., Malone, E.L. (Eds.), 1999. Carbon Sequestration in Soils: Science, Monitoring and Beyond. Battelle Press, Columbus, OH.

21.6.2 Resources “4 per 1000” initiative: http://4p1000.org/understand. CSiTE (Carbon Sequestration in Terrestrial Ecosystems): http://csite.esd.ornl.gov. European Biofuels Technology Platform (EBTP): www.biofuelstp.eu/overview.html. Free air CO2 enrichment (FACE) experiments: AmazonFACE: http://amazonface.org. Arizona FACE: www.ltrr.arizona.edu/Bsleavitt/MaricopaFACE.htm. Aspen (Rhinelander) FACE: http://aspenface.mtu.edu. Bangor FACE: www.bangor.ac.uk/senrgy/research/facilities/bangor_free_air.php.en.

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BiFor-FCE: www.birmingham.ac.uk/bifor. BioCON Face: www.biocon.umn.edu. BNL FACE research: www.bnl.gov/face/faceProgram.asp. Duke Forest FACE: www.bnl.gov/face/Duke_Forest_FACE_Performance.asp. EucFACE: www.uws.edu.au/hie/facilities/EucFACE. Euro FACE: www.unitus.it/euroface. GiFACE: www.uni-giessen.de/faculties/f08/departments/plantecology/facilities/ukl/projects/ giface/giessen-free-air-co2-enrichment-facility. Mohave Desert FACE: http://web.unlv.edu/Climate_Change_Research/NDFF/NDFF_index. html. Oak Ridge FACE: http://face.ornl.gov/index.html. Oz FACE: www.cse.csiro.au/research/ras/ozface. Soy FACE: www.igb.illinois.edu/soyface. US DOE FACE Data Management System: http://facedata.ornl.gov/global_face.html. International Centre for Research in Agroforestry (ICRAF): www.worldagroforestry.org. US Geological Survey, National Wetlands Research Center: www.nwrc.usgs.gov. International Biochar Initiative: www.biochar-international.org. IPCC, 2000. Special Report on Land Use, Land-Use Change and Forestry. Available at www.grida.no/publications/other/ipcc_sr/?src 5 /climate/ipcc/land_use. UNEP, 2009. Blue carbon (Nellemann, C., Corcoran, E., Duarte, C.M., Valde´s, L., DeYoung, C., Fonseca, L., and Grimsditch, G.) UNEP rapid response assessment. Available at www. grida.no/publications/rr/blue-carbon/. UNEP, 2009. The Natural Fix? The role of ecosystems in climate mitigation (Trumper, K., Bertzky, M., Dickson, B., van der Heijden, G., Jenkins, M., Manning, P.) UNEP rapid response assessment. Available at www.grida.no/files/publications/natural-fix/ BioseqRRA_scr.pdf.

CO2 utilization and other sequestration options

22

While CO2 has traditionally been used in a wide range of industrial processes, from the carbonation of soft drinks to the production of fertilizers, few applications result in a reduction of CO2 emissions since products such as urea and methanol (global production of which currently utilizes B120 Mt and 10 Mt-CO2/year, respectively) have a very short lifetime, typically in the order of 1 year, before the CO2 is released to the atmosphere. However, CO2 utilization had been an area of considerable R&D interest in recent years, driven at least in part by the perceived risks of other options for the long-term storage of captured CO2. Options can be grouped into low-energy processes for the production of chemicals such as urea, carbonates, and polycarbonates in which the carbon atom remains in an oxidized state, and high-energy processes for the production of fuels, in which the carbon atom is successively reduced by the replacement of C
O bonds by C
H bonds. Among the low-energy processes, the production of PCC and polycarbonates, and the enhanced use of CO2 in the production of cement and other building materials, have the potential for long-term growth to a significant scale (utilization in the order of hundreds of Mt-CO2/year). Of the high-energy processes, the conversion of CO2 to fuels, either using off-peak renewable energy or by artificial photosynthesis, holds out the possibility of true impact scale fossil fuel substitution, as also does CO2 utilization as feedstock for algal biofuel production. Reuse for fuel production may be carbon neutral or carbon negative, depending on the CO2 source (e.g., captured from fossil fuel combustion, from biofuel combustion or direct air capture) and whether CO2 is subsequently captured during combustion of these fuels. The major chemical and fuel production options are discussed in the following sections.

22.1

Enhanced industrial usage

22.1.1 PCC production As described in Chapter 10, alkaline wastes from a number of industrial processes, such as ash from coal combustion and MWI or slag from steelmaking, are potential feedstocks for mineral carbonation. The potential for generating high-value products such as PCC from these wastes, while also capturing CO2, is an additional economic incentive. A number of options for CO2 capture and storage projects that Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00022-2 © 2017 Elsevier Inc. All rights reserved.

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produce PCC have been proposed or are under active commercial development, including: G

G

Mineral carbonation of alkaline wastes by direct air or flue gas capture Calcium and magnesium carbonate precipitation from seawater by flue gas capture

Whether these uses can be considered to constitute storage of CO2 will depend on the longevity of the end product and on whether CO2 is also captured from the eventual recycling of the product.

Steel mill with mineral carbonation of slag by direct air capture The use of steel slag (or other alkaline industrial wastes) in a direct air capture carbonation scheme is a possible early-stage demonstrator project that is being pursued by several companies. This relatively simple, low-tech option, illustrated in Figure 22.1, consists of a number of large basins (each B10,000 m2) into which the prepared waste material is loaded. Water is sprayed onto the basin as a fine mist, absorbing CO2 as the drops fall through the air. The solution dissolves calcium hydroxide (Ca(OH)2) as it trickles through the bed and is recycled, dissolving more CO2 and Ca(OH)2, and precipitating CaCO3 on each pass through the system. Water consumption, as a result of evaporation and droplet loss through entrainment in the wind, would be a significant proportion of the overall operating cost of such a system. Stolaroff et al. (2003) have estimated a sequestration cost of $8/tCO2 for a scheme that would sequester 32 kt-CO2/year in 140 kt of steel slag or 680 kt of concrete waste.

Other PCC production options Similar integration opportunities exist in other industries, such as the pulp and paper industry, where the capture of CO2 emissions from a paper plant could be achieved producing an otherwise energy-intensive feedstock (PCC) while also consuming waste from other industries. Makeup water

CO2

CO2

Wet well Steel slag

Slag loading/unloading system

Figure 22.1 Direct air capture of CO2 by steel slag carbonation.

Carbonated slag

CO2 utilization and other sequestration options

579

Global consumption of PCC as a feedstock for the paper, pharmaceutical, and plastics industries is a relatively modest 10 Mt/year but this could be expanded by one or two orders of magnitude by increasing the use of PCC in the cement industry. Capture of CO2 from power plant flue gas by absorption into seawater and precipitation of calcium and magnesium carbonates for use as cement additives has also been proposed. Seawater contains 0.01 mol-Ca/kg and 0.05 mol-Mg/kg, and precipitation of the carbonates can therefore capture 1 t-CO2 in 370 t-seawater, producing 2.1 t of carbonates, comprising 81% MgCO3 and 19% CaCO3. Precipitation requires a pH of B10, so that addition of an alkali such as NaOH is necessary for a seawater feed with a pH of B8. Calera Corp. opened a demonstration site in August 2008, adjacent to the Dynegy Inc. power plant at Moss Landing, Monterey County, CA. The pilot initially uses a synthetic flue gas to produce up to 10 t/day of carbonates and, with a 0.2 Mt/day seawater supply system on site, could eventually capture B600 t-CO2/day from a flue gas slip stream from the adjacent power plant.

22.1.2 Enhanced use in the cement industry In addition to the opportunities for capture at cement plants that have been discussed in previous chapters, an interesting and potentially material storage opportunity also exists where cement finds its end use—in the curing of concrete products. The use of MgO-based rather than CaO-based cements also offers the opportunity for reduced emissions on production and additional capture during product curing.

Accelerated CO2 curing of concrete products When concrete is produced by mixing cement, water, and sand or other aggregate material, the hardening process occurs as a result of the hydration of the silicate and aluminate compounds in the cement, such as allite (Ca3OSiO4) and bellite (Ca2SiO4), according to reactions: 2Ca3 OSiO4 1 6H2 O ! 3CaO  2SiO2  3H2 O 1 3CaðOHÞ2

(22.1)

2Ca2 SiO4 1 4H2 O ! 3CaO  2SiO2  3H2 O 1 CaðOHÞ2

(22.2)

These hydration processes initially form an open microcrystalline structure, which is progressively filled in and strengthened by further hydration products as the process continues over a timescale of hours to weeks. Hydration will continue as long as water is present, and poured concrete is typically cured under a layer of water or covered by an impermeable membrane for 1
2 weeks to ensure maximum strength is achieved. Precast concrete products can also be cured for 12
24 h in a steam kiln, at carefully controlled temperatures in the range of 55
75 C, in order to accelerate early strength gain, although steam production adds an additional energy and emissions

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cost to the production process. Curing in a CO2-rich atmosphere for B1 h at 20 C has been demonstrated to be a viable and faster alternative to steam curing, which eliminates this energy cost and offers a route for the cement industry to significantly reduce its net emissions. In the curing process, CO2 reacts with the cement hydration products, principally calcium hydroxide (Ca(OH)2), to produce calcium carbonate. This carbonation reaction, which causes concrete to absorb CO2 from the atmosphere, has traditionally been considered to be undesirable. Although limited carbonation increases strength and makes concrete less permeable and more resistant to shrinkage and cracking, excessive carbonation reduces the pH of water in the cement pores, potentially leading to corrosion of steel-reinforcing bars. This is not a concern for many precast concrete products, such as concrete masonry blocks. In principle, 1 t-cement is capable of absorbing 1 t-CO2 during the hydration process if all hydration products are carbonated, while 0.5 t-CO2/t-cement is considered a more reasonable target. In practice, uptake is limited by the formation of a carbonated crust in the first 2
10 mm of the product, in which rapid carbonate infilling of pores reduces permeability by three to five orders of magnitude, preventing deeper CO2 ingress. RD&D work in the concrete industry is ongoing, focusing on increasing CO2 uptake and penetration into the product.

Magnesium silicate cement Compared to conventional cement produced using a limestone feedstock, the use of magnesium oxide (MgO) as the intermediate cement product, based on a magnesium silicate (talc) feedstock, results in a significant reduction in the CO2 footprint. Emissions due to production are reduced from B1.0 t-CO2 to 0.2
0.4 t-CO2/tcement produced, while absorption during hydration and curing is increased from B0.3 t-CO2 to 1.0 t-CO2/t-cement, giving an overall negative emission of B0.6 tCO2/t-cement produced and used. When cured in a high-CO2 atmosphere, the strength of pure MgO-based concrete blocks can exceed that of equivalent Portland cement (PC) blocks. Alternatively, the use of MgO as an additive in PC products increases the permeability of the concrete product, leading to increased CO2 uptake during curing. Commercial trials of MgO cements are being progressed by a number of companies spun off from recent RD&D projects.

22.2

CO2 conversion for fuel production

As noted above, in contrast to the relatively small-scale potential of low-energy CO2 conversion processes for chemical feedstock production, CO2 conversion for fuel production holds out the long-term possibility of eliminating anthropogenic CO2 emissions via fossil fuel substitution. Fuel production by CO2 conversion can be achieved using biological processes such as the cultivation and processing of algal biomass, discussed in the following

CO2 utilization and other sequestration options

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section, or by chemical means. The energy required to drive chemical conversion processes may either be provided by an electrical energy input in electrochemical conversion or by harvesting the energy of light in artificial photosynthesis.

22.2.1 Electrochemical CO2 conversion In electrochemical processes, an input of electrical energy drives CO2 conversion reactions in an electrolytic cell in which CO2 is reduced on the cathode while oxygen evolves at the anode. CO2 can be converted to a range of fuels and fuel precursors by this means, including CO, formic acid (HCOOH), methane (CH4), and ethylene (C2H4). The cathode typically includes a catalytic layer designed to improve the kinetics of the reduction reaction and also to be selective for a specific reaction product, e.g., a copper (Cu) electrode for methane production or silver (Ag) for CO production (Figure 22.2). A major drawback of electrochemical conversion is the cost of electricity required to drive the reaction, and this process will only ever be economically viable if the energy input comes at near-zero cost. This would be the case if electrochemical CO2 conversion consumes excess renewable energy generated by wind or photovoltaic solar systems during periods of low demand. Electrochemical CO2 reduction can then be seen as a method of extending renewable energy usage to new sectors such as aviation.

22.2.2 Artificial photosynthesis In contrast to electrochemical conversion, the energy required to drive photocatalytic conversion—artificial photosynthesis—is derived, as one would expect, from incident light. Reduction of CO2 using semiconductors as photocatalysts was first Fuel products

Oxygen Energy source

Contactor CO2

Figure 22.2 Schematic CO2 electrolyzer system.

Anode

Pump

Ion exchange membrane

Separator

Cathode

Separator

Pump

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Carbon Capture and Storage

CO2, H+

e– e– e– e– Conduction band (CB)

HCOOH, … CH4

Band gap

hν

H2O

h+ h+ h+ h+

Valence band (VB)

O2, H+

Figure 22.3 Schematic CO2 photocatalytic reduction in water.

reported in 1978 and has been extensively investigated in recent decades in view of its potential for very large-scale CO2 utilization. The basic process is illustrated in Figure 22.3. An electron in the semiconductor is excited from the valance band (VB) to the conduction band (CB) by the absorption of an incident photon (energy hν). A VB electron vacancy, which is effectively a positively charged “hole,” oxidizes (i.e., combines with an electron from) a water molecule to produce O2, releasing a proton, while the CB electrons reduce CO2 in a series of reactions to produce CO, CH3OH, CH4, etc., which also mop up the released protons. Ongoing R&D efforts are focused on a number of significant technical challenges that need to be overcome to achieve the conversion efficiencies that would enable commercial deployment.

Improved light harvesting The wide band gap from VB to CB in most semiconductors ( .3 eV in the commonly used photocatalyst TiO2) means that UV photons are required to excite electrons to the CB. Since UV light accounts for just 4% of the spectral power of incident solar light while the visible spectrum accounts for over 40%, the ability to harvest visible as well as UV photons represents a potential 10-fold increase in incident light utilization. Doping of semiconductors with cations (e.g., Ag) or anions (e.g., N) can make the photocatalyst visible light active, either by creating additional energy levels in the band gap which can be bridged by visible light photons, or by narrowing the band gap. Specific dopants have also been found to influence charge separation and product selectivity.

Charge carrier separation The electron
hole pairs generated by photon absorption have a lifetime in the order of one nanosecond (1029 s) before they recombine, the excess energy being emitted as heat. In contrast, the chemical reactions with CO2 or H2O adsorbed onto the catalyst surface are between 10 and 106 time slower. Efficient use of the photogenerated electron
hole pairs therefore requires a mechanism to prevent their rapid

CO2 utilization and other sequestration options

SC1 e–

583

SC1

SC2 e–

CB

Reduction CB

hν

hν Oxidation

SC2

e–

e–

CB

CB

hν

hν

VB

VB h+

VB

h+ h+

h+ (A)

VB Oxidation

(B)

Figure 22.4 Charge separation in semiconductor
semiconductor composite photocatalysts.

recombination. A number of approaches to this problem of charge carrier separation have been investigated, most of which rely on the use of semiconductor
semiconductor composite materials. Two such systems are illustrated in Figure 22.4. In Figure 22.4A, known as the heterojunction-type photocatalytic system, the CB and VB energy levels of the two semiconductor materials (SC1 and SC2) are arranged such that photogenerated electrons in the CB of SC1 migrate to the CB of SC2 while photogenerated holes in the VB of SC2 migrate to the VB of SC1. As well as heterojunction systems using dual semiconductors (e.g., AgBr
TiO2) similar separation behavior has also been demonstrated in a single semiconductor (TiO2) between two crystalline phases and also between two crystal facets exposed in a single crystalline phase, as a result of the different crystalline structures having subtly different band energies. A disadvantage of this system is that some of the absorbed photon energy is released as heat during charge migration, so that the energy available for the reduction and oxidation (redox) reactions is reduced to the gap between the CB edge of SC2 and the VB edge of SC1. This disadvantage is addressed in the Z-scheme system illustrated in Figure 22.4B. Here the CB electrons in SC2 recombine preferentially with VB holes in SC1 due to the lower energy gap. The separated charge carriers now have a higher redox ability due to the higher energy gap between the CB in SC1 and the VB in SC2.

CO2 adsorption and activation The reactions that progressively reduce CO2 to the desired products such as CH3OH and CH4 require the CO2 molecule to be physically or chemically adsorbed onto the catalyst surface and strongly interacting with surface atoms in order to promote the transfer of electrons. The absorbed molecule is activated by the transfer of one or more electrons from the photocatalyst, and reducing the energy barrier to achieve this activation is an important factor affecting CO2 conversion activity. Approaches to optimize adsorption and activation include: G

Preparation of photocatalysts with a large number of surface oxygen vacancies which, being reductive sites, promote both adsorption and reduction

584

G

G

Carbon Capture and Storage

Photocatalyst preparation as mesoporous structures (e.g., open frameworks, nanotubes, and nanofibers) to enhance surface area for adsorption Surface coating (known as “decoration”) of photocatalyst with additional “co-catalysts” with different functions such as strengthening adsorption and reducing activation energy.

Currently reported photocatalytic yields for CO2 reduction, in the order of 1 mmol/kgcat/h, remain several orders of magnitude below what would be required for commercial application. However, the elegance of artificial photosynthesis as a technological solution for CO2 utilization suggests that this will continue to be an active area of research for many years to come.

22.3

Algal biofuel production

When compared to cultivation of biomass crops in terrestrial agroecosystems, the aqueous cultivation of microalgal biomass as a feedstock for biofuel production, using captured CO2 as a carbon source, has a number of advantages that can lead to higher productivity per unit of land usage, as summarized in Table 22.1. These advantages are balanced by the cost of systems to supply CO2 and for continuous cultivation and harvesting, which are a major cost factor due to low biomass intensity resulting from the low concentration and microscopic nature of algal cells. Table 22.1 Advantages of aqueous microalgae cultivation for biomass production System feature

Aqueous cultivation advantage

Photosynthetic efficiency

Higher photosynthetic efficiency leads to carbon fixation rates 10
50 times higher in microalgae compared to terrestrial plants With efficient access to water, CO2, and nutrients, microalgae can lead to higher productivity per unit of land usage compared to terrestrial crops Simpler system with fewer process variables than terrestrial agroecosystem crops, making process engineering for higher yield simpler and more generic Avoids the unproductive period during which new terrestrial crops are becoming established, maximizing photosynthetic production period Enables continuous optimization of levels of CO2 and nutrients (nitrogen and phosphorus) to maximize lipid production Photosynthetic NPP is not “wasted” in constructing roots, stems, etc., which have low or zero yield of end product (e.g., compared to oilseed crops) Aqueous cultivation of algae can use poor-quality land and water that is unsuitable for conventional crop production

Land usage

Process simplicity

Continuous production and harvesting Nutrient control Specific productivity

Land and water quality

CO2 utilization and other sequestration options

585

22.3.1 Algal biomass production systems Algal cultivation in shallow open constructed ponds has been considered as a CO2 capture method for power plant flue gases, and such open systems are typically able to convert 1%
2% of total incident solar energy into stored chemical energy under the high-intensity levels typical of full sunlight. This compares to a typical 0.1%
0.2% of sunlight converted into biomass for terrestrial crops grown under similar outdoor conditions, although some crops, such as irrigated sugarcane, can achieve similar productivity to algae cultures. To capture the CO2 from a given power plant, the algae cultivation ponds would therefore have to be such that the total incident solar energy was in the order of 100 times the power plant output. Algae farms based on open ponds, as illustrated schematically in Figure 22.5, are used commercially to produce algal strains such as spirulina for use as “nutraceuticals.” Systems of this type are operated by algae producers in the United States, including Earthrise Farms, CA, and Cyanotech Corp., HI, and in several other countries, principally China and India. For use in a large-scale capture project, individual ponds would range up to 10 hectares (ha) in area, compared to typically 0.5 ha at present, with a total area of . 10,000 ha being required to capture a maximum 30% of the CO2 released from a 500 MW coal-fired power plant. This type of open pond system was demonstrated in the late 1980s on a 0.1 ha scale at the US Department of Energy site in Roswell, NM, achieving a 3.5% visible light conversion efficiency (roughly half of this level based on total solar input) and producing an extrapolated 70 t-biomass/ha-year during the summer months. A microalgal capture pilot project developed by GreenFuel Technologies and Debacsa, a subsidiary of the Spanish group Aurantia, commenced treating flue gas from a cement plant in Jerez, Spain, in December 2007 using an open pond system. A second development phase utilizing a 100 m2 prototype vertical thin-film closed

Algae

CO2 from capture system

Nutrients Algae supply Photo bioreactor

Algae separation Algae residue

Oil extraction Algal oil

Alcohol Catalyst

Transesterification

Circulating open pond system Biodiesel, Glycerine

Figure 22.5 Algae farm using bioreactor algae supply and open circulating ponds.

586

Carbon Capture and Storage

photobioreactor was initiated in late 2008, but plans for a demonstration-scale follow-up project using microalgal-derived biofuel to power a 30 MW cogeneration plant were terminated in 2009. The challenges of open pond systems and closed photobioreactors described in the following section, include: G

G

G

G

G

Poor light conversion efficiency Incomplete capture due to the inability to sustain a high [CO2] Contamination of the culture by unwanted algal species and algal predators Heat losses or overheating, requiring heating or cooling and/or limiting site applicability High cost of harvesting and processing

Contamination may be particularly problematic in open systems if an unwanted local species outcompetes a species that has been specifically selected for some characteristic such as high lipid production. However, contamination is also an issue in closed systems, which may be more difficult to clean once contaminated.

Light conversion efficiency and saturation Although algae are able to photosynthesize under very low light levels, their ability to convert incident light saturates at a light intensity roughly equivalent to a bright overcast day (about one-tenth of full direct sunlight). At higher intensities overall light conversion efficiency is reduced and incident light above this saturation intensity (IS) is wasted. For the roughly 10-fold increase in light intensity from IS up to a full sunlit day, only a Btwo- to threefold increase in photosynthetic conversion will occur in a static aqueous culture, so that 70%
80% of solar energy is wasted as a result of saturation. Incident light above the saturation intensity can still be efficiently used if the duration of illumination is very short (,1 ms) and the dark period is about five times longer. Such “flashing light” effects have been shown to increase photosynthetic rates in algal mass cultures. Several solutions that have been proposed and tested to overcome this saturation limitation and increase light conversion efficiency are summarized in Table 22.2. One aspect of the genetic engineering of algal strains is the possibility of reducing the concentration in microalgae of so-called antenna pigments, often primarily chlorophyll, to improve the utilization of photons captured for photosynthesis. This would reduce the amount of non-productive photon capture that occurs at the surface while increasing irradiance deeper in the culture, thus increasing overall productivity.

Development and demonstration of closed algae production systems A number of companies are developing closed photobioreactors, typically using one or more of these approaches to increase light conversion efficiency beyond that achievable in open ponds. Temperature and nutrient levels can also be more easily and continuously controlled in closed reactor systems, further improving

CO2 utilization and other sequestration options

587

Table 22.2 Methods to increase light conversion efficiency in microalgae cultivation Approach

Description

Turbulent mixing

Increasing the turbulence of the culture under illumination results in increased light conversion efficiency since under illuminated culture is frequently brought up to the saturation intensity level Use of optical systems, such as waveguides, to conduct high-intensity incident sunlight and distribute more uniformly throughout the bioreactor Vertical reactor geometry to increase the surface to volume ratio and achieve more uniform illumination close to the saturation intensity Variations in light sensitivity of different species of algae provide the opportunity to optimize light conversion efficiency through species selection and engineering (e.g., reducing the “antenna” pigment)

Light redistribution

Reactor geometry

Selection and genetic engineering of algal species

productivity, although O2 saturation also needs to be managed to avoid growth inhibition due to oxygen toxicity. One example is Green Fuel’s 3D Matrix System, which increases area to volume ratio in excess of 500-fold compared to open ponds, and achieved productivity of up to 1.7 t-biomass/ha-day (ash-free, dry biomass weight) in field trials capturing flue gas CO2 from power plants, including a trial at the APS Redhawk 1.06 GW gas-fired combined-cycle plant near Phoenix, AZ. In 2014, Pond Biofuels began operating an algal production demonstration facility, using raw flue gas from Votorantim’s St. Mary’s Cement plant in Ontario, Canada as carbon source. Supplementing the moderate sunlight levels and shorter daylight hours at this latitude, the 20 m3 bioreactor is illuminated by customdesigned flashing red LED arrays. The long-term target of the project is to establish a commercial-scale facility producing 225 kt/year of algal biomass and 29,000 m3/year of algal-derived oil. A two-stage algae production system that combines closed photobioreactors with open ponds has been developed by Cellana (previously HR BioPetroleum) in Hawaii. The closed reactor is used to produce a pure feed culture, which is then transferred into the open ponds for batch cultivation (see Huntley and Redalje, 2007). This approach achieves the main advantage of the closed photobioreactor in eliminating contamination, since residence time in the open ponds is reduced, while also minimizing cost through use of the open pond system. A small pilot system, consisting of several closed reactors and open ponds with a capacity of 600 m3, has been in operation at Kona in Hawaii since 2004 and was expanded to 2.5 ha in a joint venture with Royal Dutch Shell which ran from 2007 to 2011. Although Shell pulled out of the venture in 2011, Cellana continues to

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Carbon Capture and Storage

develop the technology and is evaluating potential sites for a 1000 ha demonstration-scale facility to produce 100 kt/year of algal biomass.

Photobioreactor carbon delivery options The photobioreactor approach typically involves bubbling CO2 through the reactor, with carryover gas containing any excess CO2 that is not absorbed by the culture being emitted to the atmosphere. CO2-rich flue gas can also be bubbled through the culture liquid external to the reactor, in a separate “bioscrubber.” CO2 loading in the reactor can be increased by using micro-bubbles (diameter 10
50 μm, which dissolve faster than larger bubbles due to their high surface to volume ratio) and can also fully dissolve while rising in shallow ponds due to their lower buoyant velocity. Hollow-fiber membranes have also been investigated for gaseous CO2 delivery in photobioreactors. As an alternative to gaseous CO2, sodium or ammonium bicarbonate—by-products of NaOH and aqueous ammonia based capture systems (see Chapter 6)—have also been used as carbon sources for microalgae cultivation. A further novel approach, proposed by TNO in the Netherlands (Ko¨nst et al., 2017), is to integrate algae production in a more traditional absorber
regenerator configuration, as illustrated in Figure 22.6. In this scheme, which has been demonstrated at laboratory scale, carbon is delivered to the photobioreactor dissolved in the rich solvent, with lean, regenerated solvent recirculated to the absorber. Absorption is preceded by flue-gas scrubbing to remove SOx and NOx, which can inhibit algal growth. Although details of the solvent used in the TNO demonstration have not been published, similar patented systems propose carbonate solutions (e.g., Na2CO3) as the CO2 sorbent, with the bicarbonate-rich solvent transported as the carbon source to the bioreactor, where the carbonate is regenerated. CO2-lean gas to stack

Absorber

Water make-up

Lean solvent cooler Rich solvent Biomass/ Bioproducts Photobioreactor

Flue gas

Flue gas scrubber Lean solvent

Figure 22.6 Integration of absorption capture with algal solvent regeneration.

CO2 utilization and other sequestration options

589

22.3.2 Fuel production from algal biomass Although algal biomass can be used without further processing as a feedstock for fish farming (aquaculture) or as a solid fuel for power generation, the main organic components can also be processed into high-value products: proteins can be used as animal feed, carbohydrates can be fermented to produce bioethanol, and lipids (oils and fats produced for energy storage) can be used for biodiesel production. Algae are potentially well suited as a feedstock for biodiesel production, since some strains can produce lipid levels up to 60% of the dry biomass weight when certain nutrients are limited; active nutrient control can therefore be used to maximize lipid production, although it has yet to be demonstrated that algae with a high lipid content ( .30% dry weight) can also be productive in mass cultures. Lipids can be extracted from algal biomass by a number of processes, which may include drying or the use of solvents, depending on the algal species, strain, and growing conditions. Two potential processes are: G

G

Cell disruption followed by emulsification with recycled oil and centrifuging Cold press extraction of 75%
80% of the oil, followed by solvent extraction using hexane (C6H14) or diethyl ether (C2H5OC2H5), the solvents then being separated and recovered by distillation. Extraction can also be achieved using a supercritical fluid such as scCO2 or methanol.

Extracted lipids are mostly in the form of triglycerides, in which a long-chain fatty acid is attached to each of the three hydroxyl (OH) groups of a glycerol molecule (C3H5(OH)3). Conversion to biofuels (diesel or jet fuel) involves the process of transesterification, shown in Figure 22.7, in which the triglyceride is catalytically reacted with a simple alcohol, such as methanol or ethanol, transforming the triglyceride into three methyl or ethyl esters of the fatty acids and releasing the glycerol molecule. The catalyst for the reaction is a strong base such as sodium or potassium hydroxide (NaOH, KOH). Separation of the reaction products is by settling due to density differences, and the light biofuel fraction is then finished by washing and drying.

22.3.3 Research focus in algae and biodiesel production Current R&D work aims to increase algal productivity toward a target level of 100 t-biomass/ha-year with an oil content target of 40% triglycerides, in order to CH2 CH CH2

OCOR1 OCOR2

CH2 + 3CH3OH

Catalyst ←→

OCOR3

Triglyceride

CH CH2

+ Methanol

←→

OH OH

+

OH

Glycerol

Figure 22.7 Transesterification of triglyceride to produce biodiesel.

+

R1

COOCH3

R2

COOCH3

R3

COOCH3

Methyl esters

590

Carbon Capture and Storage

minimize land usage and reduce the cost of production, harvesting, and processing to the point where algal biofuels become cost-competitive with traditional fuels. The following areas are being addressed by ongoing R&D and pilot-scale demonstration programs: G

G

G

G

G

G

G

G

Optimization of photobioreactor configuration to overcome light saturation effects and achieve other productivity benefits Alternative bioreactor designs for microalgae cultivation (e.g., growth of biofilms in porous support bioreactors) Protection of the open pond cultures against invasion by other algal strains Genetic engineering to reduce antenna pigment concentration and increase oil yield Optimization and control systems for photobioreactors (irradiance, nutrients, acidity, etc.) to maximize product yield Development of low-cost harvesting systems for specific algal strains (e.g., centrifugation, filtration, floatation, and flocculation) Processing of harvested algal biomass to extract oil and yield high-value residues In situ transesterification of lipids without prior extraction from algal biomass

22.4

References and resources

22.4.1 References Aresta, M., Dibenedetto, A., Angelini, A., 2013. The changing paradigm in CO2 utilization. J. CO2 Utilization. 3
4, 65
73. Benemann, J.R., 1997. CO2 mitigation with microalgae systems. Energy Convers. Manage. 38 (Suppl.), S475
S479. Benemann, J.R., Oswald, W.J., 1996. Systems and economic analysis of microalgae ponds for conversion of CO2 to biomass. Final Report to US Department of Energy National Energy Technology Laboratory. Burlew, J.S. (Ed.), 1953. Algal Culture from Laboratory to Pilot Plant. Carnegie Institution for Science, Washington, DC. Hoenig, V., Hoppe, H., Emberger, B., 2007. Carbon capture technology: options and potentials for the cement industry. European Cement Research Academy report TR 044/2007. Huntley, M., Redalje, D.G., 2007. CO2 mitigation and renewable oil from photosynthetic microbes: a new appraisal. Mitig. Adapt. Strat. Global Change. 12, 573
608. Jang, J.G., Kim, G.M., Kim, H.J., Lee, H.K., 2016. Review on recent advances in CO2 utilization and sequestration technologies in cement-based materials. Constr. Build. Mater. 127, 762
773. Ko¨nst, P., Mireles, I.H., van Os, P., van der Stel, R., Goetheer, E., 2017. Integrated system for capturing CO2 as feedstock for algae production. Energy Procedia. 114, 7126
7132. Lam, M.K., Lee, K.T., Mohamed, A.R., 2012. Current status and challenges on microalgaebased carbon capture. Int. J. Greenhouse Gas Control. 10, 456
469. Lu, Q., Xiao, F., 2016. Electrochemical CO2 reduction: electrocatalyst, reaction mechanism, and process engineering. Nano Energy. 29, 439
456. Pires, J.C.M., Alvim-Ferraz, M.C.M., Martins, F.G., Simo˜es, M., 2012. Carbon dioxide capture from flue gases using microalgae: engineering aspects and biorefinery concept. Renewable Sustainable Energy Rev. 16, 3043
3053.

CO2 utilization and other sequestration options

591

Podola, B., Li, T., Melkonian, M., 2017. Porous substrate bioreactors: a paradigm shift in microalgal biotechnology? Trends Biotechnol. 35, 121
132. Rinco´n, J., Camarillo, R., Martı´nez, F., Jime´nez, C., Tosto´n, S., 2015. Greenhouse effect mitigation through photocatalytic technology. In: Jime´nez, E., et al., (Eds.), Environment, Energy and Climate Change I: Environmental Chemistry of Pollutants and Wastes. Springer-Verlag, Berlin. Sheehan, J., Dunahay, T., Benemann J.R., Roessler, P., 1998. A look back at the US Department of Energy’s aquatic species program: biodiesel from algae. NETL report NETL/TP-580-24190. Stolaroff, J.K., Lowry, G.V., Keith, D.W., 2003. Using CaO- and MgO-rich industrial waste streams for carbon sequestration. Energy Convers. Manage. 46, 687
699. Yuan, L., Xu, Y.J., 2016. Photocatalytic conversion of CO2 into value-added and renewable fuels. Appl. Surf. Sci. 342, 154
167.

22.4.2 Resources AlgaeLink (manufacturer of commercial-scale algae cultivation equipment and algae-to-fuel technology): www.algaelink.nl. Biodiesel Magazine: www.biodieselmagazine.com. BIOFAT project (EU pilot project for biofuel production from algae): www.biofatproject.eu/ Project. Blue Planet Ltd. (carbon-negative building materials production using carbon capture & mineralization technology): www.blueplanet-ltd.com/#technology. Calera Corp. (CO2 capture for PCC production as a cement additive): www.calera.com. Carbon Sense Solutions Inc. (CO2 accelerated concrete curing): www.carbonsensesolutions. com/pages/projects.html. Cellana Inc. (biofuel production from algae): www.cellana.com. Pond Technologies Inc. (closed-loop algal biomass production systems): www.pondbiofuels. com. Solidia Technologies Inc. (low-carbon cement production, including CO2 sequestration during curing): www.solidia.com. University of Tsukuba, Japan, Algal Biomass Energy System Research Center: www.algaebiomass-tsukuba.jp/en/index.html.

Carbon dioxide transportation

23

The large-scale deployment of CCS will require the development of a transportation infrastructure to interconnect capture and storage sites, in all but the few cases in which these two are fortuitously co-located. With a single 500 MWe power plant potentially delivering B4
5 Mt-CO2/year for storage, regional solutions such as pipeline networks with capacities in the range of 50
100 Mt-CO2/year are likely to be developed to reduce costs and provide flexibility. While road and rail transport have been used at a smaller scale, pipeline and marine transport are the only realistic options for transportation on this scale, and only these options are considered here. Key components of these two transportation options are shown in Figure 23.1. A future large-scale CO2 transport system is likely to include both pipelines and ships, as is the case in the current global market for natural gas. Ships provide a flexible and easily scalable option, which will be economically preferred for large transport distances and smaller volumes; the economic trade-off involves a number of factors including the construction and operating costs of pipelines, vessels and related liquefaction/storage/loading facilities, as well as vessel fleet size and scheduling optimization. The pipeline versus ship transport trade-off is shown schematically in Figure 23.2. As well as being economically preferred for high rate, short distance transportation, pipelines will also provide onshore regional trunk line (back-bone) and aggregation systems and may also be constructed on an intercontinental scale (.3000 km) if quantities in excess of B20 Mt-CO2/year need to be transported over such distances. The technology for pipeline and marine transport is already well developed, with many CO2 pipelines in operation and with marine transport of LPG being straightforwardly scalable for large-scale CO2 handling. This chapter therefore focuses on the current technologies and applications, and the further development and optimization needed to bring these to a regional scale.

23.1

Pipeline transportation

Although CO2 transportation in pipelines is possible in the vapor phase, all existing pipelines are designed to carry a dense phase and therefore to operate above the CO2 critical pressure (Pc 5 7.38 MPa). This has the advantage of smaller pipelines and lower pressure drops, and therefore lower energy requirements, for a given mass flow rate.

Carbon Capture and Storage. DOI: http://dx.doi.org/10.1016/B978-0-12-812041-5.00023-4 © 2017 Elsevier Inc. All rights reserved.

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Carbon Capture and Storage

Capture

Conditioning

Liquefaction

Compression

Pipeline Storage

Storage

Loading

Shipping

Offloading

Figure 23.1 CCS transportation system elements.

700

600

Vessel transport preferred

Distance (km)

500

400

300 Offshore pipeline transport preferred 200 Single pipeline

100

Dual pipeline

0 10

20

30

40

50

60

Massflow (Mt/year)

Figure 23.2 Optimal CO2 transport solution. Source: After Geske et al. (2015).

23.1.1 Pipeline engineering fundamentals Fluid flow The pressure drop due to friction per unit length of pipeline, Δ p/ΔL (Pa/m), depends on the diameter and internal roughness of the pipeline, the fluid flow rate, and the density and viscosity of the transported fluid, according to the Darcy
Weisbach equation: Δp=ΔL 5 fD ρ u2 =2D

(23.1)

Carbon dioxide transportation

597

CO2 density (kg/m3)

1000

280 K

800

300 K 310 K

600

330 K

400 400 K 200 Pc = 7.38 MPa

0 5.0

10.0 Pressure (MPa)

15.0

Figure 23.3 Density of CO2 at (P,T) relevant for pipeline operations.

where u is the fluid velocity (m3/s), D is the pipeline diameter (m), ρ is the fluid density (B877 kg/m3 for CO2 at 11 MPa and 25 C), and fD is the dimensionless Darcy friction factor. The Darcy friction factor depends on the Reynolds number (Re) and the surface roughness of the pipe (ε). The Reynolds number is defined as: _ πD Re 5 4m=μ

(23.2)

where m_ is the mass flow rate (kg/s) and μ is the fluid viscosity (7.73 3 1025 Pa s for CO2 at 11 MPa and 25 C). For example, the flow in a 0.4 m diameter pipeline transporting 3.5 Mt-CO2/year will have a Reynolds number of 4.5 3 106. The Darcy friction factor can be determined iteratively using the Colebrook
White equation: 21=2

fD

1=2

5 22log10 fε=3:7D 1 2:51=RefD g

(23.3)

where the surface roughness ε is typically 4.6 3 1025m for commercial steel pipe. For the example used above, with Re 5 4.5 3 106, fD will be B0.014, giving an estimate of the pipeline pressure drop of B15.2 Pa/m, or 1.5 MPa/100 km. This calculation gives an estimate of the pressure drop over a pipeline but does not consider the change in fluid properties with temperature and pressure, particularly close to the critical point. This is illustrated in Figure 23.3, which shows the density of CO2 for temperatures and pressures relevant to pipeline operations. At pressures , 9 MPa and temperatures . 25 C (.298K), both density and compressibility vary considerably with P and T. At the extreme, density drops by 50% for a 10 C temperature increase from 25 C to 35 C (B300 2 310K) at pressures B8 MPa. The transported dense phase may be either a supercritical fluid or a subcooled liquid, depending on whether the temperature is above or below the critical temperature (Tc 5 31.1 C). Subcooled liquid transportation has the advantage of higher

598

Carbon Capture and Storage

density (Figure 23.2) and lower compressibility, leading to smaller pipe diameters and lower pressure drops compared to a supercritical fluid. Cooling to , 15 C would typically be required, depending on distance, ambient conditions, and pipeline insulation, to ensure that the fluid remains above its boiling point along the full length of a pipeline segment. The cost trade-off between these two options will be strongly influenced by the ambient conditions, with subcooled liquid being more likely to be preferred in cooler climates or for subsea pipelines. The flow-determining properties of density and compressibility are also significantly affected by the presence of impurities such as water, hydrogen sulfide (H2S), and methane. Under these circumstances, the accurate prediction of flow behavior requires complex flow modeling, particularly in any pipeline segments where the operating pressure drops below 10 MPa. Operating experience of CO2 pipelines to date has been mostly with natural CO2 transported for EOR use. For CCS transportation, the impact on dense-phase fluid properties of trace quantities of SOx, NOx, and, in the case of pre-combustion capture, H2 has been the subject of several investigations. In general, expected trace quantities of impurities have no impact on pipeline flow characteristics, although the presence of a few mol% H2 can result in a noticeable increase in compression power requirements.

Pipeline and equipment materials issues The economic imperative to minimize capital cost dictates the use of carbon steel for pipeline construction, and the properties of this material, particularly its strength and corrosion resistance, determine the basis for design of the system.

Pipeline corrosion If the water concentration in the CO2 stream exceeds the solubility limit at the pipeline operating pressure and temperature, free water will be present and will result in the formation of carbonic acid (H2CO3), which will corrode carbon steel pipelines. This type of corrosion is slow and results in pitting of the steel surface, eventually leading to pinhole leaks. The corrosion risk can be mitigated by dehydration of the CO2 stream to below the solubility limit and inclusion of a corrosion allowance in the design wall thickness of the pipeline. Similarly, the concentration of hydrogen sulfide in the fluid stream must be kept below the solubility limit to prevent H2S corrosion, while the concentration of H2 (e.g., from pre-combustion capture) must be limited to avoid hydrogen embrittlement (see Glossary). A recommended quality specification for pipeline transportation of CO2 has been published by the European Union’s Dynamis project, as summarized in Table 23.1. Recommended practices for the design, construction, and operation of CO2 pipelines were issued by DNV (2010), and subsequent experimental programs, conducted as part of the CO2PIPETRANS Joint Industry Project, have aimed to address knowledge gaps relating to the impact of water content and impurities on CO2 pipeline corrosion. Starting from the Dynamis specification in Table 23.1, these studies concluded that the suggested water and impurity concentrations are

Carbon dioxide transportation

599

Table 23.1 EU Dynamis recommended CO2 specification for transportation and storage Component

Concentration limit

Consideration

H2O H2S CO SOx NOx O2

500 ppm 200 ppm 2000 ppm 100 ppm 100 ppm ,4 vol% ,1000 ppm ,4 vol% ,2 vol% ,4 vol% total

Prevention of free water Health and safety Health and safety Health and safety Health and safety For aquifer storage Technical limit, for EOR For aquifer storage For EOR Lower for H2 in view of economic value of its energy content

CH4 N2 1 Ar 1 H2

too high to be the basis of a safe operating window if “safe” is defined as no corrosion and no formation of solid corrosion products (such as sulfur and FeCO3) in the bulk CO2 phase, which could potentially lead to equipment or pipeline plugging and impaired reservoir injectivity. Corrosion was largely eliminated when water content was reduced to 50 ppm, one-tenth of the Dynamis specification, except in experiments where NO2 was present. This remains an area of uncertainty and, until data validated corrosion models are available, case-specific experimental corrosion studies will be required to define safe operating conditions in designs where impurities are present, even when water content is as low as 50 ppm. Carbon steel pipelines also require external corrosion protection, which may be achieved by coatings, cathodic protection, or both.

Pipeline fracture failure Two types of fracture failure can occur in pipelines in CO2 service: brittle fractures from stress corrosion cracking and ductile fractures. Brittle fractures occur where stresses are concentrated as a result of corrosion, causing small cracks that can then grow catastrophically. The ability of a material to resist brittle fracturing once a small crack has developed is known as the toughness, or fracture toughness. It is recognized that CO2 pipelines are at greater risk of failure from long-running axial brittle fractures as a result of the severe Joule
Thomson cooling and embrittlement that occurs around any leak, for example, as a result of carbonic acid corrosion. Ductile fractures occur when stresses exceed the normal tensile strength of the material, resulting in failure after plastic deformation. Large pressure transients that can occur as a result of phase changes during depressurization are a potential cause of ductile failure specific to CO2 pipelines, and management of this hazard requires careful operational control. In the CO2 pipeline systems operating in the United States, it is common practice to install fracture or crack arrestors to impede the explosive propagation of axial

600

Carbon Capture and Storage

fractures. These typically consist of glass fiber wrapped around the pipe and embedded in an epoxy resin, although steel hoops are also used. Arrestors are placed every 100
3000 m, depending on the class of location in terms of the population density of the surrounding area, and dual arrestors are often installed side by side to ensure that any crack is fully arrested. A further important element of the pipeline design is the inclusion of isolation or block valves at intervals along the pipeline in order to mitigate the risk of a major release of CO2 in the event of a pipeline rupture. These would be closed in by the pipeline control system in the event that a leak is detected, minimizing the pipeline inventory that would be released. For a given block valve separation, a safe distance can be calculated at which CO2 released in a major rupture would be dissipated to a safe level. The optimal block valve separation is then a balance between leak risk, including the additional risk of leakage from the valves, the safe distance in relation to local population density, and cost—both capital cost and additional operating cost for valve maintenance. Typical distances between block valves vary from 5 to 40 km, depending once again on the class of location.

Other materials issues Other materials issues relevant to pipelines and related equipment in CO2 service are summarized in Table 23.2.

Flow assurance: hydrate formation Hydrates of CO2 (CO2  5.75H2O), discussed in Chapter 9, can be formed in a CO2 pipeline if free water is present and the operating temperature drops below B15 C. The resulting ice-like solid can plug the pipeline and can be extremely difficult to remove once in place. The simplest way to avoid this flow assurance problem in CO2 pipelines where the operating temperature may fall into this range (particularly subsea pipelines) is to dehydrate the gas stream to ensure that free water never condenses. As noted above, this is also required in order to avoid carbonic acid corrosion and results in a Table 23.2 Materials considerations for CO2 service Materials issue

Description and mitigation

Elastomeric seals Diffusion of CO2 into elastomeric materials, used, for example, in pump and valve seals, can result in explosive decompression if the operating pressure drops suddenly. Selection and testing of low permeable and harder elastomers is required to minimize CO2 diffusion and decompression risk Lubrication The poor lubricating properties of dry CO2 affect pump design and internal pipeline cleaning and scraping (known as “pigging”). Petroleum-based and some synthetic lubricants harden and become ineffective in CO2 service; special inorganic greases are required

Carbon dioxide transportation

601

maximum permissible water content for CO2 transportation of 3
5 3 1024 kg/m3 (300
500 ppm). Hydrate formation is a well-known risk in natural gas wells and pipelines and is managed by the injection of hydrate inhibitors, most commonly methanol, which lower the hydrate formation temperature to below the minimum expected operating temperature. Injection of inhibitors may also be applicable in CO2 transportation operations when transient low temperatures are expected, for example, as a result of Joule
Thomson cooling during depressurization for maintenance.

23.1.2 Pipeline operating considerations The operating characteristics of CO2 pipelines are significantly affected by the pressure and temperature variability of density and compressibility, and operating procedures specific to CO2 service are needed to cater for this (Table 23.3). Table 23.3 Operational considerations for CO2 pipeline systems Operating issue

Description and mitigation

Depressurization

Rapid depressurization will result in extreme cooling (270 C to 280 C) and solid CO2 desublimation. Careful control of depressurization is required, for example, during maintenance operations, to avoid thermal stresses on the pipeline, valves, and other equipment that may cause embrittlement and fracture failure. Rapid depressurization in the early stage of blowdown can be slowed or interrupted to prevent very low pipeline and equipment metal temperatures and solid CO2 formation. Similar problems need to be addressed on repressurization Unlike natural gas or oil pipelines, which operate at pressures (oil) or temperatures (gas) far from the critical point, CO2 pipelines operate with both P and T relatively close to the critical point. Pressure transients can cause significant density and compressibility changes, and in extreme cases a phase transition. CO2 pipelines experience the so-called slinky effect under pressure transients, the equivalent of a water hammer in an incompressible fluid Detection of leaks is more difficult than with hydrocarbon pipelines due to the high-temperature dependence of compressibility of the fluid. Due to the extreme cooling experienced during a leak, aerial surveying using thermal imaging is the most effective leakdetection method for CO2 pipelines Linepack occurs when a pump feeding a pipeline segment continues to operate after the pipeline is closed in downstream. This results in a pressure increase and buildup of pipeline inventory that may be difficult to release safely. This can be mitigated with appropriate control system design and hardware redundancy

Pressure transients

Leak detection

Linepack

602

Carbon Capture and Storage

Table 23.4 Some currently operating and planned long-distance CO2 pipelines Pipeline, start-up year/Origin and destination

Length (km)

Diameter (m)

Operating pressure (MPa)

Capacity (Mt-CO2/ year)

Canyon Reef Carriers, 1972. McCamey gasification plant to SACROC oilfield, TX Cortez, 1984. McElmo Dome CO2 field, CO, to Denver City Hub, TX Sheep Mountain, Bravo Dome CO2 field, CO, to Denver City Hub and Texas oilfields Weyburn, 2000. Gasification plant ND, USA, to Weyburn oilfield, Canada Bati Raman, 1983. Donan field, Turkey Snøhvit, Norway Green Pipeline, 2010. Jackson Dome to Texas oilfields extension Rafferty CO2 Pipeline, 2014. Boundary Dam power plant to Weyburn Unit EOR Quest Project, Alberta, 2015. Oil sands upgrader to aquifer storage site

224

0.4

803

0.6

9.5
13.6

19.3

653

0.5 and 0.6

8.4
13.9

9.5

5.2

328 90 153 200

5.0 1.1 0.7

0.2 0.6

66 100

0.4

240

0.4

145

0.35

350

0.4

17.0

1.0

20.0

1.0

Planned Alberta Carbon Trunkline, 2017. Gasification upgrader to EOR fields Compostilla project, Spain, timing TBA. 300 MW oxyfuel demonstrator to saline aquifer storage Lobos Pipeline, timing TBA. St. John’s CO2 Field, AZ to Texas EOR

14.6 15.0

1.3

6.0

23.1.3 Pipeline transportation systems: current and planned Pipelines for CO2 transportation have been in operation since the 1970s, primarily to deliver CO2 to EOR projects. Table 23.4 summaries the key features of a number of these systems. The Cortez, Canyon Reef, and Sheep Mountain pipelines noted in the table are part of a network of pipelines that stretches from Colorado to Texas, connecting a number of natural and anthropogenic CO2 sources to supply gas for EOR in Texas. The network includes the world’s largest CO2 hub located in Denver City, TX, which currently handles up to 80 Mt-CO2/year. The infrastructure requirements for Europe-wide CO2 transportation have been studies in the EU FP7 funded CO2Europipe project, which ran from 2011 to 2013. The main objectives of the project were to describe the infrastructure required for

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Possible development phases 1st

2nd

3rd

4th

Figure 23.4 Possible development phases of a North Sea CO2 transport network.

large-scale transport of CO2, including injection facilities at the storage sites, and to describe the options for reuse of existing natural gas transportation infrastructure. In addition, the project generated a number of scenarios for infrastructure development, starting with initial CCS demonstration projects which coalesce into a largescale CO2 infrastructure. Figure 23.4 illustrates one possible scenario for the phased implementation of a North Sea pipeline network by 2030.

23.1.4 Pipeline transportation case studies Texas Gulf Coast CO2 network The current network of CO2 pipelines in operation in the United States extends to B6200 km, and studies indicate that this will need to be extended by an additional 17,500
37,000 km between 2010 and 2050, depending on the scope of CCS implementation. The west Texas network has been progressively developed, and continues to be extended, in response to the demand for CO2 to drive EOR projects in the Permian Basin. The additional economic incentive resulting from an EOR demand would also be the driver for a potential CO2 supply network in the Texas Gulf Coast region, where geological studies indicate that 1.5 billion barrels of oil could be recovered from existing fields by CO2 flooding. A pipeline network has been envisaged to supply 31 of the largest candidate fields with 40
50 Mt-CO2/year captured from 11 gas- and coal-fired power stations in the region. The key parameters of the network are summarized in Table 23.5.

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Table 23.5 Key parameters of a proposed Texas Gulf Coast CO2 pipeline network Parameter

Description

Network dimensions CO2 supply Gas-fired plant

1600
1820 km, 0.2 to 1.0 m diameter carbon steel pipelines

Coal-fired plant Operating pressure Total CO2 sequestration

Six stations, ranging from 460 to 1420 MWe, total 4.6 GWe Supplying 27 Mt-CO2/year Five stations, ranging from 180 to 892 MWe, total 2.6 GWe Supplying 25 Mt-CO2/year 9.0
14.0 MPa, with two booster compressor stations 0.8
1.3 Gt-CO2 over a 20- to 25-year economic life

North Sea CO2 network With roughly half of all projected European storage capacity located under the North Sea, a major part in saline aquifers off Scotland, expected CCS growth as well as EOR opportunities is expected to lead to the development of a CO2 transportation network extending across the UK, Norwegian, and Dutch sectors of the North Sea. The first link of this network is already in place with Statoil’s 153 km Snøhvit pipeline and possible future phases of development are illustrated in Figure 23.4. Front-end engineering design studies have been undertaken for a number of projects that could be part of the first UK phase of such a network. One such project was the 850 MWe Teesside IGCC project (formerly the Eston Grange IGCC project), proposed by Progressive Energy Ltd., which envisaged a 500 km, 0.7 m diameter trunk line, initially delivering 5 Mt-CO2/year from a number of capture sites to North Sea EOR projects. The preliminary design basis specified operation at 10.0
19.0 MPa, a 40-year design life, and flexibility for capacity increase up to 15 Mt-CO2/year. The system would include a number of tie-in points to allow future spur lines to connect to various oil fields along the route. Another proposed UK CCS demonstrator, the Don Valley project, envisaged a 68 km, 0.6 m diameter onshore pipeline with associated infrastructure including pig traps and block valves. A pumping station at Barmston on the east coast would connect to a 90 km, 0.6 m offshore pipeline. The system would operate at 15 MPa onshore, 18.5 MPa offshore, and have a maximum capacity of 17 Mt-CO2/year to enable transportation from multiple regional CO2 sources to aquifer storage or EOR projects in the North Sea, via an offshore distribution hub. However, both of these projects have been canceled due to a lack of hoped for funding from the UK Government CCS commercialization program. Another proposed early North Sea project with some unusual transportation aspects is the Dutch ROAD (Rotterdam Opslag en Afvang Demonstratieproject i.e., Capture and Storage Demonstration project), designed to transport CO2 from the 1.0 GWe

Carbon dioxide transportation

605

post-combustion capture-ready Maasvlakte Power Plant 3 which was commissioned by E.ON in 2013. With transportation and storage partners GDF SUEZ E & P Netherlands and TAQA Offshore, the project plans to transport 1.1 Mt-CO2/year via 5 km onshore and 20 km offshore pipelines of 0.4 m diameter to a depleted gas field in the North Sea. Uniquely, because of the low reservoir pressure (2 MPa), gas would initially be transported in the gas phase, heated to a maximum of 80 C to avoid hydrate formation as a result of Joule
Thomson cooling. The pipelines would be thermally insulated to maintain the offshore gas arrival temperature, which is economically feasible due to the relatively short distance involved. Operation of the system would be more complex than for a dense-phase pipeline, since liquid condensation would occur in the cold pipeline at start-up or on re-start after shutdowns. In December 2015, a cheaper alternative was announced by operator E.ON, the CO2 stream being injected to enhance recovery in an operating oil and gas field just 3.5 km offshore that could be reached using a deviated onshore injection, saving the pipeline cost. Initial steps toward large-scale pipeline transportation infrastructure, in Europe and elsewhere, will be developed by individual projects such as those described above; this is similar to the situation in the United States where the pipeline network established to supply CO2 from natural sources to EOR projects provides a backbone that is being extended for CCS application. Development of optimized networks, efficiently linking geographically dispersed sources with the available and publicly acceptable storage sites (perhaps only offshore and in different countries from the sources) will be facilitated by coordinated transnational planning, focusing on such factors as early appraisal of storage capacity, pipeline routing and sizing (including pre-investment funding) for future expansion, and location of new sources (i.e., new power generation capacity).

23.1.5 RD&D for pipeline transportation in CCS projects Although CO2 pipelines have been in use since 1972, and the Permian Basin EOR network alone currently transports close to 30 Mt-CO2/year, significant knowledge gaps remain regarding the transport of CO2 in CCS applications. These issues are summarized in Table 23.6. Compared to other aspects of CCS technologies, ongoing RD&D projects addressing the challenges of pipeline transportation are relatively few. The state of the art in CO2 transport has been assessed in the CO2PIPETRANS Joint Industry Project being undertaken by DNV. As noted above, Phase 1 of the project documented recommended practices for the design and operation of CO2 pipelines and also established knowledge gaps in the areas of pipeline design, materials, operations, and integrity assessments which are being addressed through experimental and modeling research in Phase 2. In association with the Norwegian research institute SINTEF, Statoil has established a CO2 flow-loop at its Research Centre in Trondheim to investigate and validate models for depressurization, two-phase flow transients, and heat

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Table 23.6 Current RD&D topics for CCS pipeline systems RD&D topic

Description

Physical properties

Impact of impurities on water solubility and other properties affecting transportation systems. Viscosity measurement of CO2 mixtures. Optimization of equation of state representations of properties of CO2, including the impact of impurities, to allow accurate pipeline modeling Burst testing of line pipe under CO2 service to validate fracture propagation models developed for hydrocarbon service. Fracture propagation behavior of subsea CO2 pipelines. Applicability of current crack arrestors and assessment methods Experimental investigations of corrosion mechanisms and rates in CO2 service, including the impact of impurities in the gas stream. Development of corrosion prediction models for different steel specifications. Identification of suitable corrosion inhibitors Testing to establish material compatibility for CO2 service, including impact of impurities in the CO2 stream. Development of standards for the qualification of materials, especially soft components such as seals Experimental investigations and data gathering to validate flow modeling and establish pipeline control algorithms. Investigation of two-phase flow regime, including impact of impurities, and consequences for operating strategies. Development of models for heat transfer, thermodynamic, and transport properties of CO2 mixtures during depressurization Investigation of conditions for hydrate formation and dissociation, and potential hydrate inhibitors. Determine water content limits to avoid hydrate formation

Ductile fracture propagation

Corrosion prediction

Material properties and compatibility

Flow modeling and validation

CO2 hydrate management

transfer in CO2 pipelines, as well as assessing the impact of impurities on these processes. The facility is also used for the training of staff operating Statoil’s Snøhvit pipeline—the world’s first offshore CO2 pipeline which began operations in April 2008. Enel and Eni have also established a pilot pipeline loop to study dense-phase CO2 transport at the Enel Federico II power station in Brindisi, as a precursor to the transport of CO2 from the plant for injection into Eni’s depleted Stogit gas field at Cortemaggiore, Piacenza, B850 km to the north. An amine-based capture pilot commenced at the Brindisi plant in March 2011, with 8500 t-CO2/year being liquefied and transported by road to the storage site. Inauguration of the pipeline link was initially planned for 2012, but by 2016 the project was still seeking environmental approvals at the injection site.

Carbon dioxide transportation

23.2

607

Marine transportation

Transportation of liquefied hydrocarbon gas in very large LPG and LNG carriers is a major contributor to global energy trade, with LNG trade standing at 240 Mt (in 2014), and provides a body of proven technology and operating experience as a basis for the development of marine options for CO2 transportation. The largest LNG carriers (Q-Max) have a capacity of 266,000 m3 and could carry 0.23 Mt-CO2 at the anticipated transport conditions for CO2.

23.2.1 Optimal physical conditions for marine transport Since LNG (methane) and LPG (propane and butane) can be liquefied by cooling at atmospheric pressure, large carriers transport LNG and LPG as a liquid in refrigerated tanks at or slightly above atmospheric pressure (up to B30 kPa). This type of fully refrigerated carrier is not suitable for the transport of CO2, which has a triple point pressure of 520 kPa, since CO2 is either a solid or gas at atmospheric pressure. Transport efficiency is maximized if the density of liquid CO2 is as high as possible and, in the region of the triple point, density increases rapidly with decreasing pressure, reaching 1200 kg/m3 at the triple point. The optimal condition for CO2 transport is thus at a pressure and temperature slightly above but as close to the triple point as can be operationally managed; the risk is the formation of solid CO2 (dry ice) if the pressure drops below the triple point pressure during loading and unloading. The likely operating conditions for a large CO2 carrier would therefore be at a temperature and pressure in the range of 230 to 250 C and 0.6 to 1.5 MPa, which is similar to the operating condition of existing semi-pressurized LPG carriers.

23.2.2 Design, development, and future deployment of CO2 carriers The existing global fleet of operating CO2 carriers is limited to a few small vessels with capacities of 1000
1500 m3 transporting liquefied food-grade CO2 at a temperature of 230 C and a pressure of 1.8
2.0 MPa. Current shipped volume is B1 Mt-CO2/year. In anticipation of a growth in volume as a result of CCS projects, the Norwegian shipping company IM Skaugen AS specifically designed six LPG carriers of 10,000 m3 capacity to be CO2-capable, and these have been operating since 2003, although not yet in CO2 service. The next generation of midrange CO2 carriers has been the subject of a number of research and engineering projects, including one led by Statoil together with SINTEF, Vigor/Fabricom, and Navion/Teekay. The project designed a 177 m long by 31 m wide vessel capable of transporting 20,000 m3 of liquefied CO2 (B24 kt-CO2) at 0.7 MPa and approximately 250 C in four to six tanks. The design, illustrated in Figure 23.5, included an offloading turret to enable direct CO2 discharge at offshore installations.

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Carbon Capture and Storage

Figure 23.5 Conceptual arrangement for CO2 ship. Source: Courtesy, Statoil/SINTEF/Teekay/Vigor, used with permission from Statoil.

As well as this low-pressure design, medium- and high-pressure options have also been considered (see Gassnova, 2016). A medium-pressure ship, operating at 1.5
2 MPa and 225 to 230 C, would build on the experience gained with foodgrade CO2 transport and is therefore a relatively mature concept, while the less mature high-pressure option (4.5 MPa, 110 C) has a more technically challenging tank and piping system but has the advantage of requiring little or no injection power offshore. Marine transport has been considered as an option in a number of potential CCS projects. As part of a shortlisted project in the UK government’s CCS Demonstration Competition, led by RWE nPower and Peel Energy, IM Skaugen AS and Teekay Corp., marine transport was considered as part of the infrastructure solution for transport to storage in depleted gas reservoirs in Tullow Oil’s Hewett Field in the UK sector of southern North Sea.

23.2.3 Operational aspects of marine transportation The operational aspects of marine transportation of CO2 are largely understood as a result of existing experience with small-scale CO2 shipping, as well as the transfer of experience from large-scale LPG and LNG operations. Integration of the continuous capture process with batch transportation in ships requires both liquefaction and storage facilities at the loading terminal. Intermediate storage for liquefied gas transportation is typically designed at B150% of the ship capacity, to allow a buffer for operational flexibility. Storage would either be in steel tanks or in underground caverns which, in suitable areas, would likely be cost advantageous for capacities of B50,000 m3 and above. Unlined rock caverns with capacities up to 250,000 m3 are currently used for refrigerated LNG and LPG storage.

Carbon dioxide transportation

609

In the initial loading operation, the cargo tanks would first be pressurized with gaseous CO2 to avoid the Joule
Thomson cooling and dry ice formation that would occur if liquid CO2 was admitted to an unpressurized tank. In LNG or LPG transport, boil-off gas evolved during the voyage can be used to fuel the ship, whereas in the case of CO2 transport, boil-off gas would probably be released to the atmosphere. Net emission could be reduced by recovering cold energy for use in onboard refrigeration or air conditioning, or onboard reliquefaction may also be possible. Offloading may be into a similar terminal facility, with onward transportation by pipeline to storage sites. Alternatively, offloading may occur at offshore locations for direct injection into the storage site, for example, by connecting the ship to an offloading platform or a submerged turret loading system. In either case the cargo tanks would be left charged with dry gaseous CO2 in preparation for the next loading cycle. While offshore unloading may appear to be a straightforward adaptation of existing offloading systems, such as are used at LNG terminals, standards to qualify the technology for CO2 service are yet to be developed. Without storage facilities, operational challenges will include the need to match the offloading rate to the achievable injection rate of the wells—driving as further optimization between well count (including sparing) and fleet size. If water depth at the offshore injection site exceeds the buoyancy depth, it might be feasible to construct temporary ocean-bottom storage using a geomembrane to confine the supercritical fluid—similar to the long-term storage concept outlined in Chapter 20. Managing the reheating and pressurization of the subcooled liquid back to a supercritical state, avoiding phase transitions and operational problems due to the cryogenic temperatures, would require heat input and additional offshore facilities, perhaps including heat engines to reduce external energy input by utilizing the cold energy from the cargo. The techno-economic optimization of a transportation solution can be a challenging problem, even for a simple project where all infrastructure decisions are with a single operator, working in a single permitting regime. Developing a greenfield CO2 transportation network on a regional scale, such as would be required for impact-scale CCS implementation in Europe, may well turn out to be a greater challenge than maturing and deploying the capture and storage technologies that have been discussed throughout this book. From the recent experience of many would-be CCS demonstration project developers, whose projects have succumbed to the vagaries of national energy and climate policies, it is clear that a far stronger political will, aligned across national borders, will be required for this challenge to be met.

23.3

References and resources

23.3.1 References Aspelund, A., et al., 2006. Ship transport of CO2. Chem. Eng. Res. Des. 84 (A9), 847
855. Brown, J., Graver, B., Gulbrandsen, E., Dugstad, A., Morland, B., 2014. Update of DNV recommended practice RP-J202 with focus on CO2 corrosion with impurities. Energy Procedia. 63, 2432
2441.

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Decarre, S., Berthiaud, J., Butin, N., Guillaume-Combecave, J.-L., 2010. CO2 maritime transportation. Int. J. Greenhouse Gas Control. 4, 857
864. DNV, 2010. Recommended Practice DNV-RP-J202, Design and Operation of CO2 Pipelines. Available at http://rules.dnvgl.com/docs/pdf/DNV/codes/docs/2010-04/RP-J202.pdf. Dooley, J., et al., 2008. Comparing existing pipeline networks with the potential scale of future US CO2 pipeline networks. Proceedings of the Ninth International Conference on Greenhouse Gas Control Technologies. Elsevier, Oxford, UK. Gale, J., Davison, J., 2004. Transmission of CO2-safety and economic considerations. Energy. 29, 1319
1328. Gassnova, 2016. Feasibility study for full-scale CCS in Norway. Report for the Norwegian Ministry of Petroleum and Energy. Available at www.gassnova.no/en/Documents. Geske, J., Berghout, N., van den Broek, M., 2015. Cost-effective balance between CO2 vessel and pipeline transport: Part I
Impact of optimally sized vessels and fleets. Int. J. Greenhouse Gas Control. 36, 175
188. Hetland, J., Barnett, J., Read, A., Zapatero, J., Veltin, J., 2014. CO2 transport systems development: Status of three large European CCS demonstration projects with EEPR funding. Energy Procedia. 63, 2458
2466. IEAGHG, 2004. Ship transport of CO2, Report PH4/30. IEA Greenhouse Gas R&D Programme, Cheltenham, UK. Lund, H., M. Hammer, S.T. Munkejord, 2014. Recommendations on models and modelling tools for CO2 transport. SINTEF Energy Research Report, Project 11029. Neele, F., et al., 2013. A roadmap towards a European CO2 transport infrastructure. Energy Procedia. 37, 7774
7782. Skovholt, O., 1993. CO2 transportation systems. Energy Convers. Manage. 34, 1095
1103. Stewart, R.J., Scott, V., Haszeldine, S., Ainger, D., Argent, S., 2014. The feasibility of a European-wide integrated CO2 transport network. Greenhouse Gases: Sci. Technol. 4, 481
494. Svensson, R., et al., 2004. Transportation systems for CO2—application to carbon capture and storage. Energy Convers. Manage. 45, 2343
2353. U.K. Department for Business Enterprise and Regulatory Reform, 2007. Development of a CO2 Transport and Storage Network in the North Sea. Visser, E., et al., 2008. Dynamis CO2 quality recommendations. Int. J. Greenhouse Gas Control. 2, 478
484.

23.3.2 Resources CO2PIPETRANS (JIP focusing on dense-phase CO2 release model validation data, fracture arrest and pipeline corrosion): www.dnvgl.com/oilgas/joint-industry-projects/ongoingjips/co2pipetrans.html. DNV (developing CO2 pipeline transportation standards under the CO2PIPETRANS JIP): www.dnvgl.com. EC/EU Dynamis project (developing CO2 quality recommendation for pipeline transportation): www.sintef.no/projectweb/dynamis-hypogen. Europipe (developing Europe-wide infrastructure for CO2 transport and injection): www. co2europipe.eu. Kinder Morgan CO2 Company (KMCO2; CO2 pipeline infrastructure and EOR oilfield operator): www.kindermorgan.com/business/co2.

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Pipeline Research Council International (PRCI; CO2 pipeline RD&D priorities): www.prci.org. SINTEF (Norwegian R&D organization active in CO2 transportation and process technology): www.sintef.no. Statoil (CO2 pipeline infrastructure in the Norwegian North Sea): www.statoil.com/en/ TechnologyInnovation.

Acknowledgments

Cansolvs is a registered trademark of Shell Global Solutions International B.V. Cryocapt is a registered trademark of Air Liquide S.A. Cynaras is a registered trademark of Schlumberger/Cameron. DMXt is a registered trademark of IFP Energies Nouvelles. ECO2s is a registered trademark of Powerspan Corp. Econamine FG Plust is a registered trademark of Fluor Corp. EverCRETEt is a registered trademark of Schlumberger. Generons is a registered trademark of the Dow Chemical Company. Inconels is a registered trademark of Special Metals Corp. Polarist is a registered trademark of Membrane Technology and Research, Inc. Prisms is a registered trademark of the Monsanto Company. Selexols is a registered trademark of Union Carbide Corp. Separext is a registered trademark of UOP-Honeywell Inc. Skymines is a registered trademark of Skyonic Inc. Teflons is a registered trademark of E. I. du Pont de Nemours and Company. ThermaLockt is a registered trademark of Halliburton Company. Every effort has been made to acknowledge registered names and trademarks. Any omissions should be advised to the publisher and will be corrected in a future edition.

CCS technology glossary

A

Absorption Physical or chemical absorption is a process in which atoms or molecules of a gas or liquid enter the bulk phase of another material (liquid or solid) and are taken up within the volume, for example gas adsorption into a liquid or liquid into a solid. See Adsorption. Adiabatic An adiabatic process is a thermodynamic process in which no heat is transferred to or released from the working fluid. An adiabatic process that is also reversible is isentropic. Adsorption A physical or chemical process in which molecules of a gas or liquid adhere to the surface of a solid adsorbent material. See also Pressure-swing adsorption, Temperature-swing adsorption, Electrical-swing adsorption. Aquifer A porous and permeable geological formation containing water. Saline aquifers contain water that is non-potable without desalination. Austenite Austenite is a face-centered cubic crystallization phase of iron that, for pure iron, is stable between 912
C and 1394
C. With the addition of alloying elements such as Cr, Ni, and Mn, this so-called γ phase can be made to remain stable down to room temperature, as a result of the precipitation of carbides (e.g., Fe3C, Fe7C3) as the steel solidifies. Austenitic steels are FeCrNi alloys with 1625% Cr, 137% Ni, and ,0.24% C. The original austenitic manganese steel was invented in 1882 by Sir Robert Hadfield. Azeotrope An azeotrope is a mixture of two or more chemicals (e.g., CO2 and methane) such that the ratio of constituents in the vapor phase is the same as in the liquid phase. As a result of this constant ratio, the components in the azeotrope cannot be separated by distillation unless an additive is introduced to break the azeotrope.

B

Barrer The Barrer, named after Richard Barrer, a New Zealand chemist and pioneer in the measurement of gas permeation, is a cgs unit of gas permeability, for example through a membrane. One Barrer equals 10210 cm2 s21 cm Hg21 or, in SI units, 7.50 3 10218 m2 s21 Pa21. Biochar Biochar is a charcoal resulting from the pyrolysis of biomass—either naturally occurring as a result of wildfires or as a result of biomass pyrolysis for bioenergy production. Applied as a soil amendment it is expected to sustainably sequester carbon while also improving soil functioning. Biofuels Biofuels are any fuels (solid, liquid, or gas) derived from biomass or other biological material, and are characterized by “generation” according to the type of feedstock; first-generation—carbohydrate feedstocks such as sugars and starch that have a direct alternative use as foods; second-generation—non-food carbohydrate feedstocks such as agricultural wastes and short rotation crops; third-generation—algae; fourth-generation— direct secretion of biofuel by metabolic engineering of photosynthetic microorganisms.

636

CCS technology glossary

Brayton cycle A thermodynamic cycle that describes the operation of internal combustion engines, including gas turbines. The cycle comprises compression of the working fluid, heating by combustion with an injected fuel, expansion against a piston or turbine, and cooling to return the working fluid to the initial state.

C

Carbonate buffering A geochemical effect that results in the acidity (pH) of ocean water being stabilized. If ocean pH increases, the ionization of H2CO3 and subsequently of the bicarbonate ion HCO32 results in the release of H1, resulting in a stabilizing drop in pH. The resulting carbonate ion may then be precipitated as calcium carbonate (CaCO3). If ocean pH drops (acidity increasing), carbonate ions recombine with H1, reducing H1 availability and increasing pH. While the carbonate ion is available, the impact of CO2 dissolution on ocean acidity is reduced as a result of this buffering, but once the carbonate ion concentration becomes depleted, further CO2 addition results in greater acidification. Carbonic anhydrase Carbonic anhydrases are a family of enzymes that catalyze the reversible conversion of CO2 and water into bicarbonate and protons. In animals the enzyme helps to maintain the acidbase balance in blood and other tissues and to remove CO2 from tissues. This hydration reaction is also central to amine- and carbonate-based absorption systems which can be enhanced using these enzymes as catalysts. Carnot cycle The Carnot cycle is an idealized reversible thermodynamic cycle that consists of a succession of four processes operating on the working fluid: an isothermal expansion at a temperature T1, a reversible adiabatic (q.v.) expansion to temperature T2, an isothermal compression at temperature T2, and finally a reversible adiabatic compression to the original state of the working fluid to complete the cycle. The French physicist Sadi Carnot proposed and studied this idealized cycle in the 1820s, in establishing the first theoretical framework to describe the steam engine. Chemical absorption An absorption process in which the sorbate chemically combines with the sorbent. Chemical looping combustion (CLC) CLC is a circulating combustion process in which the oxygen required for combustion is delivered to the combustion reactor as a metal oxide rather than as free oxygen. Reduction of the oxide releases oxygen for combustion of the fuel, and the reduced metal oxide is conveyed to a second reactor where it is reoxidized, completing the loop. Chemical vapor infiltration A membrane fabrication process in which the pores of a silica membrane are infiltrated with a gaseous or liquid precursor that is then oxidized. This process plugs the pores to form a dense membrane in which separation occurs by solutiondiffusion through the pore-filling material. Clathrate A clathrate is a molecular complex in which a guest molecule is trapped within the crystal or lattice framework of host molecules. Clathrates in which the host framework is composed of water molecules, linked by their hydrogen bonds, are also known as hydrates or clathrate hydrates, and are the basis of hydrate-based CO2 capture. Claus process An industrial process for the recovery of sulfur from a gas stream containing .25% H2S, invented by the German chemist Carl Friedrich Claus. In this process one-third of the H2S in the feed gas stream is first combusted to produce SO2 (2H2S 1 3O2!2SO2 1 2H2O), which is then catalytically reacted with the remaining H2S to form elemental sulfur plus water in the Claus reaction: 2H2S 1 SO2!3S 1 2H2O. The process is commonly applied to the H2S-rich product streams from acid gas treatment processes. Clean development mechanism (CDM) The CDM is a project-based mechanism under the Kyoto Protocol to the UN Framework Convention on Climate Change (UNFCCC) that

CCS technology glossary

637

enables the generation and issue of certified emission reductions from eligible projects, such as renewable energy and afforestation. Combined cycle When heat recovered from the working fluid of one thermodynamic cycle is used to heat the working fluid of another cycle, the cycles are described as combined. Most commonly applied to the heat recovery from Brayton cycle (gas turbine) exhaust gas to drive Rankine (steam) cycle power generation. Either cycle may be a general industrial process, and the add-on cycle is generically known as a topping cycle if at higher temperature or a bottoming cycle if at lower temperature.

D

Dendrimer A molecule composed of multiple identical branches (dendrons) around a central core, forming a tree like structure and a typically spherical symmetric geometry. Diabatic A diabatic process is a thermodynamic process in which heat is transferred to or released from the working fluid. See also Adiabatic. Directed evolution Directed evolution is a genetic engineering technique that mimics the process of evolution by natural selection, and is used to evolve organic molecules expressed by genes (such as proteins or nucleic acids) toward a desired property. This is achieved by subjecting a gene to successive rounds of mutation, thereby creating a socalled “library” of gene variants, expressing these gene variants and isolating those that show an improvement toward the desired function, and then using these “selected” variants as the starting point for the next cycle. The technique has been used to evolve the absorption catalyst carbonic anhydrase, in sulfate reducing bacteria, toward greater temperature and alkalinity tolerance. Dissolved inorganic carbon (DIC) DIC is the sum of all inorganic carbon species in a solution, including CO2, carbonic acid, and bicarbonate and carbonate anions. The average DIC in the world’s oceans is B2 3 1023 mol-C/kg.

E

Electric-swing adsorption (ESA) ESA refers to an adsorptiondesorption cycle in which sorbent regeneration is achieved using an applied electric field to heat the sorbent and release the sorbate. Endothermic An endothermic reaction requires an input of energy in the form of heat to enable the reaction to proceed. The enthalpy change of reaction ΔH is positive in an endothermic reaction (ΔH . 0). See also Exothermic. Enthalpy Enthalpy is a thermodynamic property of a system, measured in kJ/mol, and is equal to the internal energy of the system (U) plus the product of pressure (p) and volume (V) of the system (H 5 U 1 pV). Enthalpy change (ΔH) is related to the change in entropy (ΔS) by ΔH 5 TΔS 1 VΔp. Entropy Entropy is a thermodynamic quantity, measured in kJ/K-mole. It is a measure of the degree of disorder within a system, with higher entropy corresponding to a greater degree of disorder. Euphotic The euphotic (or photic) zone is the well-lit upper layer of a body of water, reaching down to the euphotic depth where light intensity has reduced to 1% of the intensity at the water surface. Depending on water turbidity the euphotic depth can be as much as 200 m in the open ocean. Exothermic An exothermic reaction releases energy, typically in the form of heat as the reaction proceeds. The enthalpy change of reaction ΔH is negative in an exothermic reaction (ΔH , 0). See also Endothermic.

638

CCS technology glossary

F

Facilitated transport membrane In a facilitated transport membrane the permeate is transported across the membrane attached to a carrier. Ferrite Ferrite is a crystallization phase of iron with a body-centered cubic crystal structure. Ferritic steels are ironchromium alloy steels with 1025% Cr, 24% Mo, ,1% Ni, and C content ,0.75%. FischerTropsch process The FischerTropsch process is a chemical reaction, most commonly catalyzed by iron or cobalt, in which a mixture of carbon monoxide and hydrogen is converted into a synthetic liquid hydrocarbon. Feedstock for the process is commonly natural gas (gas to liquids) or syngas from coal or biomass gasification. Fluidized bed reactor Fluidization of a bed of solid particles is achieved by the controlled injection of gas into the bed, causing the particles to be suspended in the flowing gas by viscous forces. The efficient heat and mass transfer that occurs in such a bed makes this an effective medium for various reactions such as pulverised solid fuel combustion and gasification. Fourth-generation biofuels See Biofuels. Functional membrane Functionalization of a membrane is the process of incorporating an active chemical group (the functional group) into the matrix or onto the pore surface of a membrane in order to enhance separation of a specific species through surface interactions with the functional group. An example of a functional membrane is the amine-modified silica membrane for CO2 separation. Membrane separation properties are strongly influenced by the density and the surface chemistry of the functional group.

G

Gas turbine cycle See Brayton cycle. Gasification Gasification is the high-temperature conversion of carbonaceous fuels, such as municipal wastes, biomass, petroleum residues, or coal, into a mixture of carbon monoxide and hydrogen by partial oxidation (C!CO) or steam reforming (C!H2 1 CO). The resulting gas (syngas) may be used directly as a fuel or as an intermediate product for the production of liquid fuel or hydrogen. Glass transition temperature The glass transition temperature is the temperature (Tg) below which an amorphous material exhibits a brittle, glassy structure. Above Tg, bonds within the material weaken and it becomes rubbery (soft and deformable without fracturing). The glassy versus rubbery distinction is important for polymeric membranes. Gross primary production (GPP) Primary production refers to the production by living organisms of chemical energy in the form of organic compounds, almost exclusively as a result of photosynthesis. Part of this energy is used by the producing organism for its own growth and maintenance; net primary production (NPP) excludes this “own use,” while GPP includes it. GPP and NPP are typically measured in t-C/ha-year.

H

Heterotroph In contrast to autotrophs, which produce organic compounds or substrates directly from inorganic carbon, heterotrophs obtain organic carbon by feeding on autotrophs or other heterotrophs. Plants and some bacteria use photosynthesis to produce organic substrates and are thus autotrophs, while other bacteria, fungi, and animals that feed on plant matter or plant products such as root exudates are heterotrophs. Higher heating value (HHV) The HHV, or gross calorific value, of a quantity of fuel is the amount of heat released when the fuel, initially at 25
C, is combusted and the combustion

CCS technology glossary

639

products are returned to 25
C. Cooling results in release of the latent heat of vaporization of the water content of the combustion products, which is therefore included in the HHV (cf. lower heating value (LHV)). Hydrocracking Hydrocracking is a chemical process in which a catalyst, in the presence of an elevated partial pressure of hydrogen, is used to break and rearrange long chain hydrocarbons. Hydrodesulfurization (hydrotreating) Hydrodesulfurization is a process used to remove sulfur from unfinished oil products such as gasoline and jet fuel. Removal of sulfur is achieved by contacting the unfinished products with hydrogen at high pressure in the presence of a catalyst. Desulfurization improves the performance of later catalytic processes, used to upgrade fuel products, and is necessary to meet environmental standards—by reducing sulfur dioxide (SO2) emissions in final combustion of the fuel. Hydrogen embrittlement When in contact with a metal surface, hydrogen atoms diffuse into the metal and recombine to form hydrogen molecules, or combine with carbon in alloy steels to produce methane, creating stress within the metal’s atomic structure. This stress can increase to levels where the metal fails due to reduced ductility, toughness, or tensile strength. Factors, such as high temperatures, which increase the solubility of hydrogen in metals, will increase the risk of hydrogen embrittlement. Hypersorption Hypersorption refers to an adsorption process using a moving or simulated moving bed of sorbent. The moving bed concept was initially patented in 1922, as a method to separate syngas components from coal gasification, although the hypersorption name was only applied from the 1940s.

I

Intergovernmental Panel on Climate Change (IPCC) Established by the World Meteorological Organization (WMO) and the United Nations Environment Programme (UNEP) in 1988, the aim of the IPCC is to assess the state of knowledge of all aspects of the climate system and of climate change, whether due to natural variability or resulting from human activities. Ion exchange Ion exchange is a process in which ions are exchanged between two electrolytes or between an electrolyte and an insoluble solid. The replacement of calcium and magnesium ions by sodium ions is an example of ion exchange that takes place during water softening. Ionic strength Ionic strength measures the total concentration of ions in solution, weighted by the square of the charge number (valency) of each species; I 5 Σicizi2 where ci and zi are the molar concentration (mol/L) and charge number of ionic species i. For ionic strength close to zero, interactions between ions can be ignored and the solution is called an ideal solution, by analogy with an ideal gas. As ionic strength increase, concentration ci is replaced by activity ai 5 fici, where fi is the I-dependent activity coefficient, to properly reflect the impact of interactions between ions. Isochoric An isochoric or constant-volume process, is a thermodynamic process in which the volume of the system under consideration remains constant. Isosteric heat (enthalpy) of adsorption The quantity of heat (enthalpy) generated when a differential quantity of a sorbate is adsorbed onto a solid surface at constant pressure.

J

Joule Thomson cooling When a gas expands, work must be done to separate molecules against the weak attractive van der Waal’s forces. If the expansion occurs without heat

640

CCS technology glossary

being exchanged with the surrounding environment, the thermal energy of the gas is expended to do this work, and the gas is cooled as a result. The effect was discovered in 1852 by physicists J.P. Joule and W. Thomson (Lord Kelvin), and is used in many industrial processes requiring cooling, including the liquefaction of gases.

L

Labile carbon See Recalcitrant carbon. Lower heating value (LHV) The LHV, or net calorific value, of a quantity of fuel is the amount of heat released when the fuel, initially at 25
C, is combusted and the combustion products are returned to 150
C. Since the end point is above 100
C the latent heat of vaporization of the water content of the combustion products is not released and is therefore not included in the LHV (cf. HHV).

M

Mafic See Ultramafic. Macroporous A porous medium having pores with a diameter .50 nm. Martensite Martensite is a metastable crystallization phase of iron formed by the rapid cooling, or quenching, of austenite (q.v.). Rapid cooling prevents carbon atoms from diffusing out of the iron crystal lattice, resulting in a body-centered tetragonal structure. Martensitic steels contain 1218% chromium, up to 1% carbon, making the steel hard but brittle, and may also include small quantities (0.22%) of nickel, molybdenum, vanadium, or tungsten. Mechanical vapor recompression (MVR) MVR is a technique to concentrate a solution by evaporation in which the heat generated by compressing vapor from the solution is use to heat the solution. One interesting application under development is the use of MVR for small-scale water desalination, as an energy efficient alternative to methods such as reverse osmosis. Mesoporous A porous medium having pores with a diameter in the range of 250 nm. Metal organic framework (MOFs) MOFs are typically three-dimensional molecular structures in which metal ions, either singly or in clusters, are inter-linked by organic ions or molecules known as ligands. Microporous A porous medium having pores with a diameter ,2 nm. Miscibility Two substances are miscible if they can be mixed in all proportions to form a homogeneous solution—that is, there is no limit to the solubility of either component in the other. Mixed ionic electronic conductors (MIECs) (mixed metal oxides) See Perovskite. Moiety A specific fragment of a molecule (e.g., an amine moiety), typically a chargecarrying species.

N

Net primary production See Gross primary production.

P

Peridotite Peridotite, an igneous rock that makes up most of the earth’s upper mantle, is a mixture of olivine ((Mg, Fe)2SiO4) and pyroxenes, which comprise a wide range of chain silicate minerals with the general formula ((Ca, Na, Fe21, Mg), (Cr, Al, Fe31, Mg, Mn, Ti, V))Si2O6. Perovskite A class of crystalline minerals with the general chemical formula ABO3, in which A is a lanthanoid element and B is a transition metal. Metal cations A and B are

CCS technology glossary

641

typically arranged in two offset cubic structures linked together by oxide anions. The first perovskite discovered was CaTiO3. MIECs are perovskite-type materials in which one or both of the A and B lattices are doped with other cations to improve stability and performance; examples are so-called LSFO (La0.5Sr0.5FeO32δ), LSCFO (La0.6Sr0.4Co0.8Fe0.2O32δ), and LSFCO (La0.2Sr0.8Fe0.8Cr0.2O3δ), where δ represents the proportion of oxide vacancies in the structure. These materials have important applications in oxygen transport membranes and solid oxide fuel cells. Pervaporation Pervaporation is a liquid separation process in which one component of a liquid mixture permeates through a membrane and evaporates into a vapor phase on the permeate side of the membrane. The word, like the process, is a combination of permeation and evaporation. Physical absorption An absorption process in which the sorbate does not chemically combine with the sorbent but is held within the sorbate by physical forces such as Van der Waals force. Pressure-swing adsorption (PSA) PSA refers to an adsorptiondesorption cycle that is driven by the drop in sorbent carrying capacity with decreasing pressure. Sorbent regeneration is achieved using a low pressure or vacuum to release the sorbate.

R

Rankine cycle A thermodynamic cycle that describes the operation of a steam engine. The cycle comprises pressurizing the working fluid in the liquid state, vaporization by heating in a boiler, expansion against a piston or turbine, typically without condensation, and cooling and condensing to return the working fluid to the initial liquid state. Recalcitrant carbon In the spectrum of susceptibility to decomposition, recalcitrant carbon occupies the middle ground between labile (easily changed) and inert material. Its resistance to decomposition is due to physical or chemical protection, for example as a result of adsorption onto mineral surfaces (physical recalcitrance) or the blocking of catabolic pathways due to the absence of essential enzymes or oxidants (chemical recalcitrance).

S

Silicoaluminophosphate (SAPO) A synthetic ceramic membrane material that is an analog of the naturally occurring zeolite chabazite ((Ca,Na2,K2,Mg)Al2Si4O12  6H2O) and is used as a molecular sieve. Soil taxonomy (USDA) A hierarchical classification of soil types according to their properties and the conditions under which they were formed. Taxonomic differentiation is based on a wide range of characteristics including physical structure (particle size, aggregation, layering), organic versus mineral content, and chemical and electrical properties. Solid oxide fuel cell (SOFC) An SOFC is a device that generates electricity directly from the electrochemical oxidation of the fuel by oxygen ions (O22) that diffuse through a solid oxide electrolyte. In the case of hydrogen as fuel, electrochemical oxidation at the anode of the cell produces water and releases two electrons from the oxygen ion, which are conducted back to the cathode through the external circuit. Specific area The total surface area of a material per unit mass (m2/kg). The rate of chemical reactions that take place on the surface of solid particles can be increased by increasing the specific area of a material, for example by grinding into smaller particles. Spinel Spinels are a class of minerals of the general form AB2O4 where A and B may be any divalent, trivalent, or quadrivalent cation, including aluminum, chromium, iron, magnesium,

642

CCS technology glossary

manganese, titanium, silicon, or zinc. The formation of a surface manganesechromium spinel layer (MnCr2O4) contributes to the corrosion resistance of alloy steels. Steam cycle See Rankine cycle. Steric hindrance Steric hindrance occurs when the presence and position of chemical groups within a large molecule prevent or hinder chemical reactions that proceed more easily in smaller molecules. Steric hindrance is exploited in the amine absorption reaction to increase the absorption capacity of the solvent, but has the associated disadvantage that the sorption rate is very low. Substrate In the context of biochemical processes in soils a substrate is an organic compound such as a root exudate or biomass decomposition product that is available for metabolism by a heterotroph, typically through the action of an extracellular enzyme (exoenzyme). Supercritical conditions A thermodynamic process is termed supercritical if its operating temperature and pressure are above the critical point of the working fluid. For example, a supercritical Rankine steam cycle operates with a live steam pressure greater than Pc 5 22.12 MPa and temperature above Tc 5 374.15
C. Syngas Syngas is the product of a gasification or steam reforming process and consists of a mixture of hydrogen and carbon monoxide.

T

Temperature-swing adsorption (TSA) TSA refers to an adsorptiondesorption cycle that is driven by the drop in sorbent carrying capacity with increasing temperature. Sorbent regeneration is achieved by heating to drive off the sorbate. Thermal efficiency The thermal efficiency of a system is the ratio of the amount of useful work or heat produced divided by the amount of heat input or the heat content of the fuel consumed in the system. For a power plant the efficiency is the amount of electrical energy produced divided by the heat value, typically the net calorific value or LLV, of the fuel consumed. See HHV, LHV. Thermocline The thermocline is the boundary layer that separates the warmer surface layers of the ocean (the epilimnion) from colder deeper water (the hypolimnion). In tropical oceans water temperature can drop from 25
C at surface to ca. 10
C below the thermocline, at 100200 m below sea level. Thermodynamic cycle A thermodynamic cycle is a sequence of changes in the state of a system such that at the end of the sequence all properties of the system (e.g., pressure, temperature, entropy) are returned to the values they had at the initial state of the cycle. Thermosiphon In a thermosiphon is a mechanism of fluid circulation in which the driving force is either fully or partially provided by the relative buoyancy of the circulating fluid when warm relative to the same fluid when cold. Third-generation biofuels See Biofuels. Transesterification The process used in biodiesel production where triglycerols present in the lipids extracted from biomass feedstock, such as oilseeds crops or algae, are converted to methyl or ethyl esters by reaction with methanol or ethanol, typically in the presence of a strong basic catalyst, such as NaOH.

U

Ultramafic rocks Mafic or ultramafic rocks are igneous rocks that are relatively poor in silica and are composed predominantly or, in the case of ultramafic rocks, almost entirely of iron and magnesium minerals. Typically, although not exclusively, ultramafic rocks

CCS technology glossary

643

contain ,45% silica and are a prospective source material for CO2 sequestration by mineral carbonation. Ultrasupercritical conditions Ultrasupercritical conditions are not defined by a specific temperature and pressure point (unlike supercritical conditions, q.v.) but they are generally taken to mean a supercritical pressure and a steam temperature .650
C. These conditions require a step-change in materials capabilities compared with typical supercritical boiler conditions (24 MPa/540
C/540
C) that have been common in the power industry since the 1980s.

V

VPDB carbonate standard The Cretaceous limestone formation at Peedee in the Vienna Basin in South Carolina (derived from the marine fossil Belemnitella americana) is used as an international reference standard for the relative abundances of carbon and oxygen isotopes. For example, for 13C the deviation of a sample from the standard is defined as:

δ13 C sample 5 1000fð13 C=12 C sample Þ=ð13 C=12 C standard Þ 2 1g where the VPDB standard ratio of 13C to 12C is 0.0112372.

W

Watergas shift (WGS) The water-gas shift (WGS) reaction is part of the process of hydrogen production from the gasification of carbonaceous fuel, in which steam reacts with carbon monoxide in syngas to produce CO2 and hydrogen. Separation of CO2 from the WGS offgas then yields a pure hydrogen stream.

Z

Zeolites Zeolites, from the Greek for “boiling stone,” are a group of naturally occurring and synthetic microporous minerals composed of hydrated sodium, potassium, calcium, or magnesium aluminosilicate. Zeolites are able to trap other molecules, such as water or gases, within their open crystal structure and as a result they have a wide range of applications as sorbents and catalysts, e.g., for amine solvent regeneration, and as molecular sieves for gas separation.

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for Adam and Jenny and their children’s children’s children

Index Note: Page numbers followed by “f” and “t” refer to figures and tables, respectively. A AABW. See Antarctic Bottom Water (AABW) ˚ bo Akademi University (A ˚ AU), 267 A Absorption, 60, 619 capture systems chemical absorption, 115
123, 125
133 physical absorption, 123
125, 126t, 133
138 technology RD&D status, 138
147 AC/ABC reaction, 121 Accelerated CO2 curing of concrete products, 579
580 Accelerated solubility trapping, 454
455, 455f Accelerated weathering of limestone process (AWL process), 119, 532 Accounting, GHG, 565
566 Acetic acid extraction, 267 Acid corrosion, 70 Acid dissociation constants, 254 Acid extraction, indirect carbonation by, 266
267 Acid gases, 51, 110 Acid rain, 60 Acidity, ocean, 9 Acronyms, CCS-related, 625
633 Activated alumina, 156t Activated carbon, 62, 155
156, 156t, 164, 193, 193t Activated MDEA (aMDEA), 117 Activation, mineral, 272
273 Active EGR pilot project—K12-B field, 480
481 Adatoms, 194 Adenosine diphosphate (ADP), 544 Adenosine-50 -triphosphate (ATP), 544 ADP. See Adenosine diphosphate (ADP) Adparticles, 151, 194

Adsorption, 619. See also Pressure swing adsorption (PSA) adsorption-based DAC, 176
177 capture systems chemical adsorption, 157
160 physical adsorption thermodynamics, 151
157 physical sorbents, 160
161 heat storage, 172
173 process configurations and operating modes, 162
171 fixed adsorption bed systems, 162 moving adsorption bed systems, 162
166 PSA processes, 167
171, 169t temperature swing adsorption/ desorption, 166
167 technology RD&D status, 171
183 Adsorption-desorption isotherms, 154f, 155 Advanced USC (A-USC), 57 Advanced Zero Emission Power Plant concept (AZEP concept), 97
98, 98f Afforestation, 564
565 AG FACE facility, 570t Agricultural carbon storage, 555
561 CA, 556
558 managing soil biogeochemistry, 558
559 manipulation of microbial communities, 560
561 Agriculture, 565 Agroforestry systems, 558 Air, composition of, 246t Air separation units (ASUs), 87, 215
216, 245
246, 246f, 247f, 250f Air staging combustion, 62 Albedo of forests, 566 Alberta Carbon Trunkline pipeline, 602t Algae production, 589
590 Algal biofuel production, 584
590, 584t research focus in algae and biodiesel production, 589
590

646

Algal biomass fuel production from, 589 production systems, 585
588, 585f development and demonstration of closed algae production systems, 586
588 light conversion efficiency and saturation, 586 photobioreactor carbon delivery options, 588 Alite (Ca3OSiO4), 579 Alkali aluminosilicates, 413 Alkali metal carbonate sorbents, 158 Alkaline industrial waste, 32, 578 rocks, 31 solid, 60 Alkaline-earth silicates. See Mineral carbonation Alkalinity of ocean, 9 Alkylation, 109 Alloying elements, 107 Alstom Power Systems, 93, 132 Alunite (KAl3(SO4)2(OH)6), 373 AmazonFACE experiments, 568t aMDEA. See Activated MDEA (aMDEA) American Petroleum Institute (API), 412 Amine -based absorption, 116
119, 118t, 125
131, 130f -based systems, 138
139 sorbents, 158 stripping, 83
84 Amine reclaimer waste sediments (ARW sediments), 130 Ammonia (NH3), 61, 116, 121 Ammonia slip, 132 Ammonia-based chemical absorption, 132
133 Ammonium bicarbonate (NH4HCO3), 121 Ammonium carbamate (NH2COONH4), 121 Ammonium carbonate ((NH4)2CO3  H2O), 121 Ammonium nitrate, 63 Ammonium sesquicarbonate ((NH4)2CO3  2NH4HCO3), 121 Ammonium sulfate, 61 indirect carbonation by extraction, 267, 268f

Index

Amplitude (AMP), 411 Amplitude versus offset analysis (AVO analysis), 494
495, 494f Anaerobic wastewater treatment, 117
119 Anhydrase enzyme, 262 Anhydrite (CaSO4), 373 Antarctic Bottom Water (AABW), 520 Antenna pigments, 586 Anthracite, 107 Anthropogenic carbon emissions, 32 change, 3
4 CO2 emissions, 3
4, 8
9, 103 emissions, 3, 5, 9, 11
13, 12f Anticline, 287f Antigorite serpentine, 258f Apache Canada-operated Midale field, 29
30, 474 API. See American Petroleum Institute (API) Approach temperature (ΔTA), 65
66 Aqueous absorption systems, 120 Aqueous ammonia-based absorption, 121, 126t Aqueous carbonate
based absorption, 119
120 Aqueous microalgae cultivation, 584t Aquifer storativity and specific yield, 388
389 AR4. See Fourth Assessment Report (AR4) AR5. See Fifth Assessment Report (AR5) Argon belly, 246 Arizona FACE facility, 570t Arrestors, 599
600 Artificial photosynthesis, 581
584, 582f, 583f charge carrier separation, 582
583 CO2 adsorption and activation, 583
584 light harvesting, 582 ARW sediments. See Amine reclaimer waste sediments (ARW sediments) Asbestos (chrysotile serpentine) mine tailings, 272 Aspen (Rhinelander) FACE facility, 567, 567f, 568t ASUs. See Air separation units (ASUs) Atmosphere, 3 Atmosphere 2 lithosphere fluxes, 11 Atmosphere 2 ocean fluxes, 9, 10f Atmosphere 2 terrestrial soil fluxes, 10
11, 10f

Index

Atmospheric carbon cycle, 3 Atmospheric carbon inventory, 5
7, 6f, 7f, 9 anthropogenic emission scenarios, 11
13, 12f CO2 stabilization scenarios, 13
14, 13f, 14f Atmospheric monitoring, 508 Atmospheric perturbation, 9 ATP. See Adenosine-50 -triphosphate (ATP) Attrition grinding, 274t A-USC. See Advanced USC (A-USC) Austenitic steels, 48, 48t, 70 Australasia, organizations and projects in, 616
618 AVO analysis. See Amplitude versus offset analysis (AVO analysis) AWL process. See Accelerated weathering of limestone process (AWL process) Azeotrope, 221, 249 AZEP concept. See Advanced Zero Emission Power Plant concept (AZEP concept)

B Bacterial respiration, 560 Bag filters, 59 Bangor FACE experiments, 568t “Barrer”, 200 Base-catalyzed hydration of CO2, 116 Basic oxygen steelmaking (BOS), 28, 107 Basin-scale hydrology, geological storage impact on, 391
393 brine displacement, 391
392 geochemical effects of CO2, 392
393 Bati Raman pipeline, 602t BCM. See Biologically controlled mineralization (BCM) Bellite (Ca2SiO4), 579 Belowground carbon allocation, 547 Benfield process, 119 Benson boiler, 53, 54f BFB. See Bubbling fluidized bed (BFB) Bi-phasic amine solvents, 138 liquid solvent R&D, 139
140, 140f liquid systems, 122 Bicarbonate ion (HCO3
), 9, 291 Bicarbonate-rich effluent stream, 532

647

BIFor-FACE experiments, 568t BIM. See Biologically induced mineralization (BIM) Biocatalytic carbon mineralization, 262
263 Biochar, 559 Biochemical recalcitrance, 549
550 BioCON FACE facility, 570t Biodiesel production, 589
590 Biofilm growth, 380
382 caprock leakage remediation, 381 FESEM images of Berea sandstone, 381f microbially enhanced trapping, 382 Biofuel. See Algal biofuel production Biofuel combustion, 112 Biogeochemical FEPs, 379 biofilm growth, 380
382 impact of CO2 injection on microbial communities, 379
380, 380t enhanced biomineralization, 382
383 subsurface microbial recycling of CO2, 383
384 Biological pump, 8, 522
523, 522f Biological sequestration macroalgal biomass development and demonstration projects, 539t ocean afforestation, 538
539 ocean iron fertilization, 533
536 wave-driven ocean upwelling, 537 Biologically controlled mineralization (BCM), 259
260 Biologically induced mineralization (BIM), 259
260 Biomass co-firing, 52 Biomass fuels, 38t. See also Algal biofuel production Biomass production systems, algal, 585
588 Biomass-powered steam-driven turbines, 23 Biomineralization, 259
263 biocatalytic carbon mineralization, 262
263 calcite precipitation by cyanobacteria, 260
262 cement remediation by, 427 “Bioscrubber”, 588 Biosphere carbon inventory, 7, 8t Black liquor, 111
112 evaporation, 112 Blast furnace gases, 107
108 Blended amine solvents, 117

648

Block valves, 600, 604 “Blue carbon”, 562 Boiler technology, 53
56 combustion chambers and burners, 55, 55f combustion technology, 55 condenser and heat recovery, 54
55 evaporator design, 53, 54f FBC, 55
56, 56f, 56t feedwater processing, 53 superheating, reheating, and steam temperature control, 53
54 BOS. See Basic oxygen steelmaking (BOS) Brayton cycle, 45
47, 46f, 47f, 64, 241 Brazilian test, 325 Brine displacement, 391
392 Brine
CO2 mutual solubility and solution properties CO2 solubility in formation brine, 341 density of aqueous CO2 solutions, 342
343 water solubility in CO2, 342 Brines, direct carbonation in, 265 Bubble point, 42 Bubbling fluidized bed (BFB), 55 Buoyancy, 517 depth, 399 Buoyant fluid, 306
307 Burners, combustion, 55 Butylene (C4H8), 109

C C3 photosynthesis, 544
547 C4 photosynthesis, 546
547 CA. See Carbonic anhydrase (CA); Conservation agriculture (CA) CACHET project, 108 CAES. See Compressed air energy storage (CAES) CAESAR project, 79, 108 Calcination, 103
104 Calcining, 146, 159
160 calcined dolomite (CaCO2  MgCO3), 166 calcined limestone, 107 Calcite (CaCO3), 265 Calcite precipitation by cyanobacteria, 260
262 Calcium aluminate (CaAl2O4), 177 Calcium carbonate (CaCO3), 27, 103, 260

Index

Calcium hydroxide, 423 Calcium ions, 382 Calcium looping (CaL), 104 Calcium sulfoaluminates (Ca4(AlO2)6SO4), 413 Calvin
Benson
Bassham cycle, 522, 544
545, 545f photosynthesis, 546
547 CAM. See Crassulacean acid metabolism (CAM) Canyon Reef Carriers pipeline, 602t CaO looping post-combustion capture, 181
182, 181f CAP. See Chilled ammonia process (CAP) Capillary condensation, 191
192, 192f entry pressure (Pce), 348 flow, viscous, 189, 190f pressure, 345
358 trapping, 288
289, 289f, 348
351 Caprock geochemical processes in, 369
370, 370f heterogeneity, 309
314 fracture systems, 310
314 stratigraphy, 309
310 permeability, 318 stratigraphy, 310 Capture efficiency, 80 Capture-ready power plant, 93
97, 95t retrofitting capture capability, 96
97, 96t, 97t Carbamate, 116, 116f CarbFix project, 280
281 Carbides, 49
50 Carbon, 517 conversion efficiency, 68 emission, 51 farming, 556 mineralization, 253 steel components, 425 stocks, 562
563 Carbon allocation, aboveground and belowground, 547, 547t Carbon capture methods, 15, 23
29, 24f, 37, 112, 253 direct air capture, 28
29 from industrial processes, 27
28 cement production, 27
28, 27t, 103
106, 104f

Index

integrated steel mills, 28 natural gas processing, 110
111 oil refining, 108
110, 109f pulp and paper production, 111
112, 111f steel production, 107
108 from power generation, 23
27, 24f, 24t, 25f, 25t, 26f, 76f advantages and disadvantages, 76t approaches to ZEP generation, 97
100 capture-ready and retrofit power plant, 93
97 chemical looping systems, 88
93 oxyfuel combustion, 86
88 post-combustion capture, 80
86 pre-combustion capture, 75
80, 77f, 77t Carbon capture and storage (CCS), 4
5, 23, 77
78, 94, 106, 108, 151, 227, 233f, 285, 393, 472, 595, 596f, 625 CCS-related online journals and newsletters, 622
623 LCA of CCS technologies, 33
35, 34f, 35t RD&D for pipeline transportation in CCS projects, 605
606 units and conversion factors, 625 Carbon cycle, 5
11 mitigating growth of atmospheric carbon inventory, 11
14 process of technology innovation, 15
19, 16t, 17t RDD&D timescale, 15
19, 18f, 19t TRL classification, 15, 17t Carbon dioxide (CO2), 115. See also CO2 trapping mechanisms adsorption and activation, 583
584 concentration, 3 conversion, 577 for fuel production, 580
584 corrosion, 425 design, development, and future deployment of CO2 carriers, 607
608, 608f dissolution, 254
256, 255f emissions, 4, 27
28, 108, 110, 396 fertilization, 552 effect, 11 geochemical effects, 392
393

649

hydrates, 231
232, 232f impact on casing and tubing, 425 impact on cement, 423
425 injection, 247 leaking from seabed, 399 liquefaction, 244 off-gas stream, 106 physical properties of in seawater, 517
518 buoyancy, 517 hydrate formation and decomposition, 518 saturation pressure, 517 pipelines, 595 plus steam off-gas, 90 properties density and compressibility of CO2, 337, 338f density of aqueous CO2 solutions, 342
343 impurities impact on, 358
362, 359t viscosity of, 337
339, 339f water solubility in, 342 removal, 111 and seawater density vs. depth, 518f solubility in formation brine, 341 stabilization scenarios, 13
14, 13f, 14f stream impurities on well integrity, 425 subsurface microbial recycling of, 383
384 transportation, 595 CCS transportation system elements, 596f marine transportation, 607
609 optimal CO2 transport solution, 596f pipeline transportation, 595
606 use in engineered geothermal systems, 484
485 utilization, 577 algal biofuel production, 584
590 enhanced industrial usage, 577
580 Carbon fluxes, 5, 5f, 8
11 atmosphere 2 lithosphere fluxes, 11 atmosphere 2 ocean fluxes, 9, 10f atmosphere 2 terrestrial biosphere and soil fluxes, 10
11, 10f Carbon inventories, 5
8, 5f, 30 of atmosphere, 6
7, 6f, 7f of biosphere and soils, 7, 8t

650

Carbon inventories (Continued) of lithosphere, 8 of oceans, 8, 8t Carbon molecular sieves (CMS), 193 membranes, 220 Carbon monoxide (CO), 6, 25, 107 Carbon Sequestration in Terrestrial Ecosystems (CSiTE), 572
573 terrestrial sequestration R&D program, 572
574, 573t Carbon Sequestration Leadership Forum (CSLF), 295 Carbon storage geological storage, 29
30 by mineral carbonation, 32 ocean storage, 30
31 in terrestrial ecosystems, 31
32 in terrestrial ecosystems, 543, 566 and use options, 33 Carbon-based fuel, 75 Carbonate buffering, 522 Carbonate ion (CO32
), 9, 291 Carbonate
silicate cycle, 11 Carbonation reactions, 32 Carbonic acid (H2CO3), 254, 291, 519
520, 598 Carbonic anhydrase (CA), 119, 260
261, 262f Carboniferous age, 3 Carnot cycle, 63
64 Carnot efficiency, 43 “Cased and perforated” completion, 416 Casing, CO2 impact on, 425 CASTOR project, 84
85 Cataclasis, 307 Catalyst-packed reactor tubes, 41 Catalytic conversion, 33 Catalytic reforming, 109 Catalytic steam reforming, 41 Catalyzed hydration mechanism, 262 CB. See Conduction band (CB) CBM. See Coal bed methane (CBM) CCGT plant. See Combined cycle gas turbine plant (CCGT plant) CCS. See Carbon capture and storage (CCS) CEMCAP project, 106 Cement CO2 impact on, 423
425 remediation by biomineralization, 427 slurry, 413

Index

Cement industry, 579
580 accelerated CO2 curing of concrete products, 579
580 magnesium silicate cement, 580 Cement production, 27
28, 103
106 carbon capture processes, 106 oxygen enrichment and oxyfuel processes, 105
106, 106t post-combustion capture from cement plants, 104
105, 105t Ceramic wafer stack modules, 208, 208f CFB system. See Circulating fluidized bed system (CFB system) Charge carrier separation, 582
583, 583f Chemical absorption, 115
123 amine-based absorption, 116
119, 118t applications amine-based chemical absorption, 125
131 ammonia-based chemical absorption, 121, 132
133 aqueous carbonate
based absorption, 119
120 enzyme-catalyzed chemical absorption, 120 phase-change solvents, 122
123 sodium hydroxide
based absorption, 121
122 Chemical activation, serpentine, 274t Chemical adsorption, 156
157, 156t, 157t amine sorbents, 158 HTCs, 158
160, 159f metal oxide sorbents, 157
158 Chemical looping, 75 hydrogen production, 92
93, 92f, 94f RD&D status CaO looping post-combustion capture, 181
182 chemical looping combustion, 180 hybrid combustion
gasification by chemical looping, 182
183 reforming, 91
92 systems, 88
93, 165
166, 166f Chemical looping combustion (CLC), 26, 89
91, 90f, 90t, 91t, 165
166 Chemical looping combustion with oxygen uncoupling (CLOU), 166 Chemical sequestration, 532
533

Index

Chemisorption, 151 Chilled ammonia process (CAP), 132, 132f, 133f CHP plants. See Combined heat and power plants (CHP plants) Chromium, 48
49 Chromium oxide (Cr2O3), 48 Chrysotile, 257 Circulating fluidized bed system (CFB system), 55, 177 Clathrate hydrates. See Gas hydrates Clathrates. See Gas hydrates Claus reaction, 373 Clay minerals, 392 Clay-binding process, 550
551 Clay-smear, 307 CLC. See Chemical looping combustion (CLC) Clean coal-fired generation, 618 Climate predictions, 4 Climate
ecosystem interactions modeling, 552
554 CLOU. See Chemical looping combustion with oxygen uncoupling (CLOU) CMIP4. See Coupled Carbon Cycle Climate Model Intercomparison Project (CMIP4) CMS. See Carbon molecular sieves (CMS) CMS pressure swing adsorption process (CMS-PSA process), 216 CO2 plume geothermal energy (CPG energy), 485, 485f CO2 Storage Data Consortium (CSDC), 431 CO2 supercritical fluid (scCO2), 285
286 CO2 trapping mechanisms, 285
294. See also Carbon dioxide (CO2) ionic trapping, 291, 292f mineral trapping, 291
292 residual trapping, 290 saline aquifer trapping mechanisms indicative specific capacities of, 292
293 time dependence of, 294 solubility trapping, 291 structural and stratigraphic trapping, 286
289 CO2
water contact (CWC), 287
288 Coal, 107, 482
483 burners, 52

651

firing, 51 gasification power plant with integrated mineral carbonation, 278
279, 279f process, 93 Coal bed methane (CBM), 482
483 Coal-fired power plant, 28. See also Fossilfueled power plants Coastal tropical savannah FACE experiments, 570t Cold sink, 66
67 Colebrook
White equation, 597 Combined cycle gas turbine plant (CCGT plant), 67, 79
80 Combined cycle power generation, 63
68, 64f combined cycle thermal efficiency, 66
67 HRSG, 65
66, 65f, 66f, 67t IGCC power generation, 67
68, 68f Combined cycle power plant, 23 Combined heat and power plants (CHP plants), 39 Combustion, 37, 51 chambers and burners, 55, 55f reactor, 88
89 technology, 55 temperatures, 64
65 Completion, well, 413
418 Completion hardware, 418 Composite polymeric membranes, 197 Composite sorbents, 178 Compressed air energy storage (CAES), 486
487 Compressibility of CO2, 337, 338f Compressive strength of rock, 325, 325t Concrete masonry blocks, 580 Concrete products, accelerated CO2 curing of, 579
580 Condenser, 54
55 Condensing turbine, 57 Conduction band (CB), 582 Conservation agriculture (CA), 556
558 conservation tillage, 556
557 crop selection, rotation, and intensified cropping, 557
558 Conservation tillage (CT), 556
557 Contained ocean-floor storage, 528
529 Contamination, 586

652

Controlled-source electromagnetic method (CSEM), 500
501, 501f surface and subsea CSEMs, 501
502 Convective mixing, 357
358 Conventional power plants, thermal efficiency, 63, 63t Conversion factors, 625 Conversion process, 109 “Cooperative” adsorption behavior, 154 COORIVA project, 79t Corrective pressure control strategies, 458
460 back-production of injected CO2 from host formation, 459 brine production from host formation, 459 hydraulic barrier creation to remediate leakage, 460 hydrodynamic regime modification, 459
460 Corrosion, 598
599 logging tools, 457 resistance, 47
48 Corrosivity, 141
142 Cortez pipeline, 602t Coupled Carbon Cycle Climate Model Intercomparison Project (CMIP4), 552 CPG energy. See CO2 plume geothermal energy (CPG energy) Crack arrestors, 599
600 Crack healing, 48 Cracking process, 109 Crassulacean acid metabolism (CAM), 546
547 photosynthesis, 546
547 Creep, 49
50 strain, 47
48 strength, 69 Critical point, 42 Critical pressure (Pc), 285
286 Crop selection, rotation, and intensified cropping, 557
558 Cross-well resistivity, 490t Cross-well seismic, 496
497, 497f Crude oil, 108
109 Cryogenic air separation, 68, 245, 245f Cryogenic carbon storage, 250
251 Cryogenic separation CO2 capture by, 239
244

Index

post-combustion, 243
244 pre-combustion, 242
243 Cryogenic systems. See also Distillation systems cryogenic oxygen production, 245
247 oxyfueling, 39
40 post-combustion capture, 83t pre-combustion capture, 77t RD&D, 249
250 resources, 619 Ryan
Holmes process for CO2
CH4 separation, 247
249 CSDC. See CO2 Storage Data Consortium (CSDC) CSEM. See Controlled-source electromagnetic method (CSEM) CSiTE. See Carbon Sequestration in Terrestrial Ecosystems (CSiTE) CSLF. See Carbon Sequestration Leadership Forum (CSLF) CT. See Conservation tillage (CT) Cupric oxide (CuO), 166 Cuprous oxide (Cu2O), 166 Curing of concrete products, accelerated CO2, 579
580 Curing process, cement, 580 CWC. See CO2
water contact (CWC) Cyanobacteria, calcite precipitation by, 260
262, 261f Cycle efficiency, 44 Cyclohexane (C6H12), 120f

D DA. See Dry alkanolamine (DA) DAC. See Direct air capture (DAC) Darcy equation, 344
345 Darcy’s law, 316
317, 344
345, 346t, 361 Darcy
Weisbach equation, 596
597 Darken equation. See Maxwell
Stefan expression Data gathering in wells, 413, 415t Deaeration, 53 DEEA. See Diethylethanolamine (DEEA) Deep waters, 520
521, 524 Degradation of amines, 117
119 Density of CO2, 337, 338f, 359 Depleted gas fields, storage in, 482 Depleted oil fields, injection below, 473

Index

Depressurization, pipeline system, 601t Desert scrub FACE experiments, 570t Desorption, 191 isotherm, 154 Det Norske Veritas (DNV), 605 Deviated wells, 452 DFN. See Discrete fracture network (DFN) DGPS. See Differential global positioning systems (DGPS) Di-calcium silicates (2CaO  SiO2), 412 Diagenesis, 307 Diatoms, 275 DIC. See Dissolved inorganic carbon (DIC) Diethylethanolamine (DEEA), 139 Differential global positioning systems (DGPS), 503
504, 507 Differential interferometric synthetic aperture radar (DInSAR), 490t, 504
505, 506f DInSAR. See Differential interferometric synthetic aperture radar (DInSAR) Dipropil-methyl-xanthine based solvent, 139
140 Direct air capture (DAC), 23, 28
29, 158 using sodium hydroxide, 143
144 steel mill with mineral carbonation of slag by, 578 Direct air CO2 capture using sodium hydroxide, 144
147, 144f, 145f, 146f, 147f Direct aqueous carbonation, 264
265 Direct carbonation routes direct aqueous carbonation, 264
265 direct gas
solid carbonation, 263
264 in seawater and brines, 265 in soils, 265
266 Direct CO2 dissolution, 524
527 free ocean CO2 enrichment experiment, 526
527 MBARI FOCE flume configuration, 527f results of experiments and field trials of, 525
526 injection, 524
532 direct CO2 dissolution, 524
527 evolution of CO2 injected into deep ocean-floor sediments, 530f

653

large-scale ocean storage field trials, 530
532 liquid CO2 injection, 527
530 Direct gas
solid carbonation, 263
264 Direct injection co-firing, 52 Direct-reduced iron (DRI), 108 Discrete fracture network (DFN), 313 Dispersion modeling, 396 Disposal options for carbonation end products, 273
275 Dissolution, direct CO2, 524
527 Dissolved inorganic carbon (DIC), 280, 519
520 Distillation process, 110 Distillation systems, 619 CO2 capture by cryogenic separation, 239
244 cryogenic carbon storage, 250
251 cryogenic systems for oxyfuel combustion, 245
247 distillation column configuration and operation, 229
231 physical fundamentals, 227
229, 228f RD&D in cryogenic and distillation technologies, 249
250 Ryan
Holmes process for CO2
CH4 separation, 247
249 Distributed temperature sensors (DTS), 418 DNV. See Det Norske Veritas (DNV) Dolomite, 177, 370 Downhole logging tools, 410
411 Drainage process, 352
355 CO2 relative permeability, 353f, 354f CO2 saturation logging, 355f DRI. See Direct-reduced iron (DRI) Drilling and casing, well, 407
409, 409f Dry alkanolamine (DA), 142f DTS. See Distributed temperature sensors (DTS) “Dual-mode” solvents, 141 Dual-reflux PSA cycle, 172, 172f Ductile pipeline fracture, 599, 606t Duke Forest FACE experiments, 568t

E Earth surface temperature variation, 4f ECBM recovery. See Enhanced coal bed methane recovery (ECBM recovery)

654

eCO2. See Elevated CO2 (eCO2) Economic limits to storage capacity, 476
478 Economizers, 54
55 Ecosystems, 395
398 land use, 396 population centers, 395
396 soils and sediments, 398 surface topography, 396
397 surface water bodies, 397
398 vegetation and terrestrial fauna, 396 ECRA project, 106 Eddy covariance measurement, 490t Effective storage capacity, limitations on, 296
297, 297t EGR. See Enhanced gas recovery (EGR) EGS. See Engineered geothermal systems (EGS) EIA process. See Environmental impact assessment process (EIA process) Elastomeric seals, 600t Electric swing adsorption (ESA), 167 Electrical resistivity tomography (ERT), 490t, 502
503, 503f, 504f Electrochemical CO2 conversion, 581, 581f Electrochemical partial oxidation process (Electropox process), 213, 213t Electromagnetic surveys, 499
503 ERT, 502
503, 503f, 504f surface and subsea CSEMs, 501
502 Electron beam FGD, 61 flue gas NOx removal, 63 Electron vacancy, 582 Electropox process. See Electrochemical partial oxidation process (Electropox process) Electrostatic precipitators, 59 Electrothermal desorption, 167 Elemental sulfur deposition, 373 Elevated CO2 (eCO2), 566
567, 572f Elevated ozone concentration (eO3), 566
567 Embrittlement, 49
50 Emission scenarios, anthropogenic, 11
13 EnCana Weyburn field, 474
479 CO2 distribution, 477f CO2 flood monitoring data, 477t geological characterization, 475, 476t

Index

inverted nine-spot and modified inverted nine-spot well patterns, 475f long-term risk assessment, 478
479 prediction, monitoring, and verification of CO2 movement, 475
476 risk assessment process input, 479t technical and economic limits to storage capacity, 476
478 ENCAP project. See European power generation consortium project (ENCAP project) Enclathration, 232
233 End products, carbonation, 273
275 Endothermic reaction, 103
104 Engineered geothermal systems (EGS), 484
485 CO2 use in, 484
485 Engineered system FEP, 407 processes affecting well integrity, 421
426 well construction and status, 407
421 well remediation, 426
427 Enhanced biomineralization, 382
383 MICP in 2D flow reactor, 383f Enhanced coal bed methane recovery (ECBM recovery), 482
484 active ECBM pilot project—PCOR, 484 Langmuir isotherms for CO2 and methane adsorption, 483f Enhanced gas recovery (EGR), 473, 479
482 active EGR pilot project—K12-B field, 480
481, 481t pressure gradients in oil and gas reservoirs, 480f unconventional CO2-EGR storage options, 481
482 Enhanced industrial usage, CO2 utilization cement industry, 579
580 PCC production, 577
579 Enhanced oil recovery (EOR), 130
131, 227, 377, 464, 472
479, 598 applications, 187 EnCana Weyburn field, 474
479 by miscible CO2 flooding, 472f planned EOR sequestration projects, 479 projects, 419 technique, 29
30 unconventional CO2-EOR storage options, 473
474

Index

Enhanced residual trapping, 454 Enthalpy of combustion, 37
38 of reaction, 258 Entrainment, 231 Entropy, 41 Environmental FEP EIA process, 400
404 environmental characteristics and ecosystems, 395
398 marine environmental aspects, 399
400 Environmental impact assessment process (EIA process), 396, 400
404, 402f consequence scale for population effects, 403t geological storage project, 401t potential receptors and consequence criteria, 403t RAM, 404f Enzyme catalyzed aqueous carbonate solvent R&D, 139 Enzyme-catalyzed chemical absorption, 120 eO3. See Elevated ozone concentration (eO3) EOR. See Enhanced oil recovery (EOR) EOS models. See Equation-of-state models (EOS models) EPSs. See Extracellular polymeric substances (EPSs) Equation-of-state models (EOS models), 340 Equilibrium vapor pressure, 227
228 ERT.Electrical resistance tomography (ERT);. See Electrical resistivity tomography (ERT) ESA. See Electric swing adsorption (ESA) Esbjerg pilot plant, 85 Ethane, 249 Ethanolamine, 116 Ethylene (C2H4), 581 ETP ZEP. See European Technology Platform for Zero Emission Fossil Fuel Power Plants (ETP ZEP) EU Dynamis specifications, 599t Euro FACE experiments, 568t Europe, organizations and projects in, 616
618 European power generation consortium project (ENCAP project), 78
80, 616
618

655

European Technology Platform for Zero Emission Fossil Fuel Power Plants (ETP ZEP), 78 European Union capture-ready and retrofit power plants, 94 pre-combustion RD&D projects, 78
80 Evaporative water loss, 144
146 Evaporator design, 53 Evaporite minerals, 356 EverCRETE, 424
425 Extracellular mineralization process, 260
261, 260f Extracellular polymeric substances (EPSs), 380
381 Pomorzany power plant, 61

F FACE experiments. See Free air CO2 enrichment (FACE experiments) Facilitated transport membranes, 198
200, 199f, 200f, 201t, 220 Fault/faulting offset, 307 reactivation, 330
331 of rock, 327
335 failure criteria, 327, 328f fault and fracture reactivation, 330
331 hydraulic fracturing, 327
329 induced seismicity, 331
335 FBC. See Fluidized bed combustion (FBC) Features, events, and processes (FEP), 299, 365 in geological storage, 299
302 distance scales, 300f time scales, 300f Fe
Cr
Ni austenitic steel, 49 FEED stage. See Front-end engineering design stage (FEED stage) Feed tray, distillation column, 229 Feedback mechanisms, terrestrial carbon cycle, 571 Feedstock, mineral carbonation alternative, 271
272 optimal, 269
271 Feitknecht compounds. See Sorptionenhanced reactions FEP. See Features, events, and processes (FEP)

656

Ferritic steels, 48t Fertilization forest, 563
564 ocean iron, 533
536 FESEM. See Field Emission Scanning Electron Microscopy (FESEM) FGD. See Flue gas desulfurization (FGD) Fick’s second law of diffusion, 423
424 Field Emission Scanning Electron Microscopy (FESEM), 380
381 Fifth Assessment Report (AR5), 13 “Filtration” process, 187 Fischer
Tropsch process, 40, 279 gas-to-liquids process, 214 liquids, 115 production, 136 Fixed adsorption bed systems, 162, 162f Fixed sorbent bed, 162, 162f “Flashing light” effects, 586 Flood basalt, in situ carbonation in, 279
280 front stability, 352 Flooding, CO2, 472 Flow modeling, pipeline, 606t Flow-through pipeline reactor, 275, 276f Flue gas desulfurization (FGD), 61, 84
85 Flue gas(es), 25
26, 54, 66, 80
83, 104, 217
218 cleanup ash and particulate removal, 59 FGD systems, 59
60 NOx control and removal, 61 wet scrubbing FGD process, 60
61 CO2 capture using sodium hydroxide, 143
144 stream, 28 Fluid flow, 596
598, 597f consequences of geochemical FEP, 375
377, 376f caprock impact, 377 host formation impact, 376
377 Fluid mobility, 352 Fluid properties of CO2, 337
339 brine
CO2 mutual solubility and solution properties, 341
343 capillary pressure, 345
358 convective mixing and solubility trapping, 357
358

Index

impurities impact on rock and fluid-flow FEPs, 358
362 relative permeability, 345
358 saline aquifer brine properties, 339
341 single-phase flow in porous media, 344
345 water
CO2 vapor phase properties, 344 wettability, 345
358 Fluid sampling, 490t Fluid-flow FEPs, impurities impact on, 358
362 impurities impact on CO2 properties, 358
362, 359t on geological storage, 360
362 Fluidized bed combustion (FBC), 55
56, 56f, 56t Fluidized bed(s), 165, 165f adsorber, 177 reactors, 90
91 Fluor solvent process, 77
78, 125, 126t, 137
138, 137f Fluor Daniel Econamine FG Plus process, 131 Fly ash, 59 removal, 51 FOCE systems. See Free Ocean CO2 Enrichment systems (FOCE systems) Forest FACE experiments, 566
567 fertilization, 563
564 forestry afforestation and reforestation, 564
565 forestry management practices, 563
564 Formation fluid sampling, 415t Formic acid (HCOOH), 581 Fossil fuel combustion, 6, 25, 37
40, 38t heating value of fuel, 39 oxyfueling, 39
40 POX, 38
39 Fossil fuel-powered steam-driven turbines, 23 Fossil-fueled power plants, 23, 43, 50
51, 50f flue gas cleanup, 59
63 fuels and fuel handling, 51
52 steam generation, 52
57 steam turbine technology, 57
59, 58f, 59f steel metallurgy for, 47
50, 48t

Index

carbides, creep, hardening, and embrittlement, 49
50 corrosion resistance, 48 thermal efficiency of conventional power plants, 63, 63t 4D seismic monitoring, 493 4D (time-lapse) seismic monitoring CO2 flood monitoring, 477t saline aquifer storage, 493
494 Fourth Assessment Report (AR4), 3 Frac-and-pack, 453 Fracture/fracturing arrestors, 599
600 failure, pipeline, 599
600 permeability, 319 pipeline, 606t reactivation, 330
331 of rock, 327
335 fault and fracture reactivation, 330
331 hydraulic fracturing, 327
329 induced seismicity, 331
335 rock failure criteria, 327, 328f systems, 310
314 DFN, 314f Krechba field development, 313f realistic and idealized geometry of, 312f Salah fracture system, 311t toughness, 599 Free air CO2 enrichment (FACE experiments), 552
554, 566
572, 567f, 568t, 570t Free Ocean CO2 Enrichment systems (FOCE systems), 526
527 Frio “C” formation, 315, 316f Front-end engineering design stage (FEED stage), 131 Fuel production from algal biomass, 589 CO2 conversion for, 580
584 artificial photosynthesis, 581
584 electrochemical CO2 conversion, 581 Fuel(s) cell, 99 and fuel handling biomass co-firing, 52 coal firing, 51 gasification, 52 natural gas firing, 51

657

oxidation reactor, 90 partial oxidation, 92
93 Furnace off-gas, 107 FutureGen project, 431 G G3P. See Glyceraldehyde 3-phosphate (G3P) Gamma aminopropyl tetramethyldisiloxane (GAP-0), 123 GAP-0. See Gamma aminopropyl tetramethyldisiloxane (GAP-0) Gas hydrates, 231
232, 518 Gas impurities, geochemical impact of, 372
374 elemental sulfur deposition, 373 mineral trapping impact, 374 Gas reservoirs, 29, 471, 479 Gas sweetening, 110 Gas turbine, 55
56 ASU integration with, 249
250, 250f Gas turbine cycle, 89 chemical looping combustion in, 90f Gas-side corrosion, 57 Gasification, 52, 75
78, 98 of fossil and fuels, 40, 40t plant, 80 Gas
liquid membrane contactors, 190
191, 191f, 222
224 Gate opening and breathing phenomena in flexible MOFs, 178
179, 179f Generation efficiency, 23 Geochemical carbon cycle, 119 composition of produced fluids, 477t leak detection in shallow aquifers, 510 processes, in saline aquifer storage, 468t reactions kinetics, 371
372 Geochemical FEPs biofilm growth, 380
382 CO2 injection impact on microbial communities, 379
380, 380t enhanced biomineralization, 382
383 in host rock and caprock, 365
374 geochemical impact of gas impurities, 372
374 geochemical processes in caprock, 369
370 geochemical processes relevant for geological storage, 366t

658

Geochemical FEPs (Continued) geochemical reactions kinetics, 371
372, 372t mineral trapping, 365
369 in overlying potable aquifers, 374
375 potential mineral sources of trace metals, 374t reactive transport modeling of storage complex, 375
379 subsurface microbial recycling of CO2, 383
384 Geological FEP components of storage complex, 306t faulting and fracturing, 327
335 mechanical rock properties rock compressibility, 324
325 tensile and compressive strength, 325, 325t thermo-elastic stress, 326 in situ stress and pore pressure, 320
324 storage formation and caprock heterogeneity, 309
314 and caprock properties, 314
319 type and geometry, 305
314 Geological storage (GS), 29
30, 30f, 285, 429 CO2 trapping mechanisms, 285
294 FEP in, 299
302 and geothermal energy, 484
485 CO2 use in engineered geothermal systems, 484
485 CPG energy, 485 integrated CO2 storage and multi-fluid geothermal system, 486f impact on basin-scale hydrology, 391
393 impurities impact on, 360
362 fluid flow, impact on, 361 leakage, impact on, 362 storage capacity, impact on, 361
362 limitations on effective storage capacity, 296
297, 297t options CAES, 486
487 enhanced coal bed methane recovery, 482
484 enhanced gas recovery, 479
482 enhanced oil recovery, 472
479 geological storage and geothermal energy, 484
485 storage in depleted gas fields, 482

Index

probabilistic storage capacity estimation, 294, 298
299, 298f storage capacity classification, 294
296 GCS capacity, 295t subsurface carbon storage options, 286t Geomechanical consequences of geochemical FEP caprock impact, 378
379, 378f host formation impact, 377
378 processes, in saline aquifer storage, 468t Geomechanical FEP components of storage complex, 306t faulting and fracturing, 327
335 mechanical rock properties rock compressibility, 324
325 tensile and compressive strength, 325, 325t thermo-elastic stress, 326 in situ stress and pore pressure, 320
324 storage formation and caprock heterogeneity, 309
314 and caprock properties, 314
319 type and geometry, 305
314 Geophones, 489, 492 Geopolymer, 413 GHG. See Greenhouse gas (GHG) GiFACE facility, 570t Glass transition temperature, 197 Glass-reinforced epoxy (GRE), 411 Global ocean circulation system, 9 Global surface temperature, 14 Global thermohaline circulation, 519, 520f Glyceraldehyde 3-phosphate (G3P), 544
545 Goldenbergwerk plant, 80 Goldeneye field, planned depleted gas field storage project, 482 Gorgon project EIA, 401 GPP. See Gross primary production (GPP) Grain boundary embrittlement, 50 Grassland FACE experiments, 570t Gravity surveys, 490t, 499
503 computed seabed gravity anomaly, 500f microgravity surveying, 499
500 GRE. See Glass-reinforced epoxy (GRE) Great Plains synfuel plant, 137 “Green liquor”, 111
112 Green Pipeline, 602t Greenhouse gas (GHG), 3, 534, 554
555 full GHG accounting for terrestrial storage, 565
566

Index

Gross primary production (GPP), 545
546 Ground surface deformation monitoring, 503
507 differential global positioning systems, 507 satellite-borne monitoring, 504
507 surface monitoring, 507 GS. See Geological storage (GS) Guerin
Domine cycle, 171, 171f

H Hall plot tool, 456, 457f Hard tissues pump, 523 Hardening, 49
50 HAT. See Humid air as turbine working fluid (HAT) Hazard identification (HAZID), 400
401 HCl. See Hydrochloric acid (HCl) HDS. See Hydrodesulfurization (HDS) Health, safety, and environmental (HSE), 395 Heat recovery, 54
55, 66 Heat recovery area (HRA), 54 Heat-recovery steam generator (HRSG), 23, 64
66, 65f, 66f, 67t, 68, 98, 98f Heating value of fuel, 39 Heavy reflux (HR), 171
172 Hemicellulose, 111
112 Henry’s law, 123, 519 Heterogeneity process, 306 storage formation and caprock, 309
314 caprock stratigraphy, 310 fracture systems, 310
314 stratigraphy, 309
310 Heterojunction-type photocatalytic system, 583 Heterotrophic respiration, 10 Hewett gas field, 481 HFMC. See Hollow-fiber membrane contactors (HFMC) HFZ. See Hydrate formation zone (HFZ) HHV. See Higher heating value (HHV) High-capacity steam turbines, 59, 59f High-frequency pressure cycling, 171 High-nutrient, low-chlorophyll (HNLC), 533

659

High-pressure (HP), 50
51 turbine exhaust steam, 51 High-temperature adsorption, 173 High-temperature molten carbonate membrane, 219, 219f High-temperature sorbents, 177
178 Higher heating value (HHV), 39 HNLC. See High-nutrient, low-chlorophyll (HNLC) Hollow-fiber membrane contactors (HFMC), 130 Hollow-fiber modules, 207
208, 207f Horizontal permeability (kh), 316
318 Horizontal wells, 328 Host formation back-production of injected CO2 from, 459 brine production from, 459 HP. See High-pressure (HP) HR. See Heavy reflux (HR) HR6W superalloy, 70t HRA. See Heat recovery area (HRA) HRSG. See Heat-recovery steam generator (HRSG) HSE. See Health, safety, and environmental (HSE) HTCs. See Hydrotalcites (HTCs) Humic material, 548
549 Humid air as turbine working fluid (HAT), 47 Humification, 548
550 Huntite (CaCO3  3MgCO3), 166 Hybrid combustion
gasification by chemical looping, 182
183, 182f Hybrid cryogenic/hydrate systems, 238
239, 238f Hybrid hydrate/membrane systems, 237
238, 237f, 238f Hydrate capture RD&D, 250 formation, 600
601 and decomposition, 518 hydrate-based capture configuration and operation of hydrate separation systems, 235
237 integrated and hybrid hydrate separation systems, 237
239 physical fundamentals, 231
235 particles, 30
31

660

Hydrate (Continued) promoters, 232, 234 separation systems, configuration and operation of hydrate, 235
237, 235f pilot-scale hydrate separation unit, 236f slurry, 235 Hydrate formation zone (HFZ), 529, 529f Hydration chemistry, 254
256 equilibrium constant, 254 Hydraulic barrier creation to remediate leakage, 460, 460f conductivity, 388 diffusivity, 389 fracturing, 327
329, 329f initiation, 328 propagation, 328
329 Hydrocarbon(s), 29, 37 production, 30 Hydrochloric acid (HCl), 121, 266 Hydrocracking, 109
110 Hydrodesulfurization (HDS), 109
110 Hydrodynamic modeling, 395 regime modification, 459
460 trapping, 289, 289f, 390 Hydrogasification, 98
99 Hydrogen, 99, 109 fuel stream, 26 production, 41, 92, 110 Hydrogen sulfide (H2S), 109
110, 115, 598 Hydrological FEP geological storage impact on basin-scale hydrology, 391
393 hydrological aspects of storage site characterization, 393
395 hydrodynamic modeling, 395 hydrological characterization, 394
395 local-and regional-scale, 387
391 aquifer storativity and specific yield, 388
389 cross section of open regional aquifer, 388f hydraulic conductivity, 388 regional hydrological regime, 389
390, 389t vadose and shallow phreatic zone processes, 390
391

Index

Hydrophone arrays, 492 Hydrotalcites (HTCs), 157t, 158
160, 159f memory effect, 159 Hypersorption process, 162
163, 163f Hyperspectral remote sensing, 490t Hyphal networks of mycorrhizal fungi, 550
551 Hysteresis adsorption isotherm, 155t relative permeability, 347, 353
354 I IAPWS97 model, 340 IEA. See International Energy Authority (IEA) IFTs. See Interfacial tensions (IFTs) IGCC. See Integrated gasification combined cycle (IGCC) ILMs. See Immobilized liquid membranes (ILMs) ILs. See Ionic liquids (ILs) Imaging spectroscopy, 490t Imbibition process, 352
355 CO2 relative permeability, 353f, 354f CO2 saturation logging, 355f IMC Global operated plant, 83 Immobilized liquid membranes (ILMs), 222 “Impact scale deployment”, 4
5 Impurities impact on CO2 properties, 358
362, 359t on geological storage, 360
362 In situ carbonation in flood basalt, 279
280 in mid-ocean ridge basalt, 280
281 mineral carbonation, 265 stress, 320
324 orientation and magnitude, determination of, 322
323 pore pressure measurement, 323
324 principal stresses and Mohr’s circle, 321
322 Inconel superalloy, 70t Indirect carbonation routes, 266
268 by acid extraction, 266
267 by ammonium sulfate extraction, 267 by extraction methods molten salt extraction, 268 sodium hydroxide extraction, 268

Index

Induced seismicity, 331
335 fault rupture area and displacement, 332
333 fault zone characteristics, 333 impact on geological storage, 333
335, 334t “Infill” wells, 474 Injection below depleted oil fields, 473 injection-withdrawal tests, 513
514 planning, 455
456 Injection well monitoring, 490t InSAR. See Interferometric synthetic aperture radar (InSAR) Integrated and hybrid hydrate separation systems hybrid cryogenic/hydrate systems, 238
239 hybrid hydrate/membrane systems, 237
238 Integrated gasification combined cycle (IGCC), 67
68, 202 fuel gas, 234, 234f plant, 110 Integrated mineral carbonation coal gasification power plant with, 278
279 steel mill with, 277
278, 278f Integrated steel mills, 28 Intensified cropping, 557
558 Interfacial tensions (IFTs), 345
346 wettability, contact angle and, 345
347 Interferometric synthetic aperture radar (InSAR), 490t, 504
507 Intergovernmental Panel on Climate Change (IPCC), 3, 12, 23 International Energy Authority (IEA), 475 Inverted nine-spot pattern, 474, 475f Ion transport membranes, 201
202 for oxygen production, 216, 217f Ion-exchange membranes. See Ion transport membranes Ion-exchange resins, 156t Ionic reaction, 9 trapping, 291, 292f Ionic liquids (ILs), 140 solvents, 140
141

661

reversible ILs, 141 TSILs, 141 IPCC. See Intergovernmental Panel on Climate Change (IPCC) Iron fertilization trials, results of, 533
535 impacts and controlling factors, 534t parameters of mesoscale, 534t and steel production, 103 Iron carbonate (FeCO3), 425 J Ja¨nschwalde power plant in Germany, 87
88 Japan, organizations and projects in, 616
618 Joule Thomson cooling, 245 K K12-B field, active EGR pilot project, 480
481, 481t Keeling curve, 6 KEPCO/MHI process, 131, 131f Ketzin Storage Pilot project, 461, 467 Knudsen diffusion, 189
191, 190f, 190t Knudsen umber (NKn), 188
189 KOH. See Potassium hydroxide (KOH) Kozeny
Carman equation, 376
377 Kraft process, 111
112 L L/S ratio. See Liquid to solid ratio (L/S ratio) Lacq-Rouse CCS demonstration pilot— Rousse field, 482 Lake Nyos disaster, 397 Land use, 396 changes in, 561
565 contributions to carbon stocks of different land uses, 561t forestry management, afforestation, and reforestation, 562
565 afforestation and reforestation, 564
565 forestry management practices, 563
564 wetland management and restoration, 561
562, 563t

662

Langmuir adsorption equation, 151
152, 197 Langmuir isotherm, 151
152, 153f Layered double hydroxides. See Sorptionenhanced reactions LCA. See Life-cycle analysis (LCA) Leak detection, pipeline system, 601t LHV. See Lower heating value (LHV) Li2ZrO3. See Lithium zirconate (Li2ZrO3) LIDAR. See Light detection and ranging (LIDAR) Life-cycle analysis (LCA), 33 of CCS technologies, 33
35, 34f, 35t Life-cycle assessment. See Life-cycle analysis (LCA) Light conversion efficiency and saturation, 586, 587t harvesting, 582 Light detection and ranging (LIDAR), 490t Light reflux (LR), 172 Linepack, pipeline system, 601t Lipids, 589 Liquefied natural gas (LNG), 607 Liquefied petroleum gas (LPG), 595 Liquid CO2 injection, 527
530 contained ocean-floor storage, 528
529 ocean-floor CO2 lakes, 527
528 storage in ocean-floor sediments, 529
530 Liquid to solid ratio (L/S ratio), 273 Lithium orthosilicate (Li4SiO4), 177 Lithium silicate (Li4SiO4), 181 Lithium zirconate (Li2ZrO3), 157t, 177 Lithosphere carbon inventory, 8 LNG. See Liquefied natural gas (LNG) Loeb-Sourirajan membrane, 204 Long-term atmosphere
ocean CO2 equilibrium, 523 Long-term risk assessment, 478
479 Los Alamos National Laboratory, 98
100, 99f, 99t Low-pressure (LP), 51, 57
58 stage, 57 Low-temperature phase behavior of CO2, 239
242, 239f, 240f reverse Carnot cycles, 241
242 Lower heating value (LHV), 39 LP. See Low-pressure (LP)

Index

LPG. See Liquefied petroleum gas (LPG) LR. See Light reflux (LR) Lubrication, pipeline, 600t

M Magnesium aluminosilicate, 160 Magnesium hydroxide (Mg(OH)2), 60 Magnesium oxide (MgO), 256, 413, 580 Magnesium silicate cement, 580 Manganese
chromium (MnCr2O4), 48 MAPA. See N-Methyl-1,3-diaminopropane (MAPA) Marine environmental aspects, 399
400 CO2 leaking from seabed, 399 recent R&D on, 399
400 ECO2 project, 399
400 QICS project, 400 “Marine snow”, 523 Marine transportation, 607
609. See also Pipeline transportation design, development, and future deployment of CO2 carriers, 607
608 operational aspects of marine transportation, 608
609 optimal physical conditions for marine transport, 607 Martensitic steels, 48t Maximum Contaminant Level (MCL), 375 Maxwell
Stefan expression, 194 MBARI. See Monterey Bay Aquarium Research Institute (MBARI) MC carbides nucleate, 49
50 MCL. See Maximum Contaminant Level (MCL) MCM. See Mixed conducting medium (MCM) MDEA. See Methyldiethanolamine (MDEA) MEA. See Monoethanolamine (MEA) Measurement, Monitoring, and Verification plan (MMV plan), 447, 448f MECC. See Mixed electron carbonate conductor (MECC) MECS sorbents. See Microencapsulated carbon sorbents (MECS sorbents) Membrane separation systems applications and technologies, 188t applications in pre-combustion capture

Index

oxygen ion transport membranes for syngas production, 213
214 palladium membranes in IGCC applications, 214
215 membrane and molecular sieve applications in oxyfuel combustion, 215
216 membrane applications in natural gas processing, 220
224 in post-combustion CO2 separation, 217
220 membrane configuration and preparation, and module construction, 203
208 membrane technology RD&D status, 209
212 physical and chemical fundamentals, 187
203 facilitated transport membranes, 198
200 ion transport membranes, 201
202 membrane configurations, 188f MMMs, 198 porous membrane transport processes, 188
195 SLMs, 202
203 solution
diffusion transport process, 195
197 Membrane Technology Research (MTR), 218 Membrane(s) module configurations, 205
208 area-to-volume ratios, 205t ceramic wafer stack modules, 208 hollow-fiber modules, 207
208, 207f spiral-wound modules, 205
207 sieves, 619 types, 204, 204f, 205t Metal oxide carrier (MexOy), 88
89 Metal oxide sorbents, 157
158 alkali metal carbonate sorbents, 158 Metal oxides, 157t Metal
organic frameworks (MOF), 154, 156t, 161, 161f, 178
180, 198 gate opening and breathing phenomena in flexible MOFs, 178
179 phase-change functionalized MOF sorbents, 179
180 Methane (CH4), 6, 116, 566, 581 syngas production from, 40
41, 40t

663

Methanol (CH3OH), 33, 124
125, 124f, 577, 601 N-Methyl-1,3-diaminopropane (MAPA), 139 Methyldiethanolamine (MDEA), 117 MgO. See Magnesium oxide (MgO) MICCP process. See Microbially induced calcium carbonate precipitation process (MICCP process) MICP. See Microbially induced calcite precipitation (MICP) Microalgal biomass, 82
83 photosynthesis, 33 Microbial activity, 566 communities, 548 impact of CO2 injection on, 379
380, 380t manipulation, 560
561 Microbial organic matter (MOM), 548
549 Microbially induced calcite precipitation (MICP), 382 Microbially induced calcium carbonate precipitation process (MICCP process), 262 Microbiota, soil, 548 Microencapsulated carbon sorbents (MECS sorbents), 142f Microseismic surveys, 490t Microwave activation, serpentine, 274t Mid-ocean ridge basalt, in situ carbonation in, 280
281 Mineral feedstock identification, 269
271, 270t, 271t trapping, 291
292, 365
369 geochemical trapping dependence on pH, 368f reactants and reaction products, 367t Mineral carbonation, 15
19, 253, 270, 277t, 620 chemical and biological fundamentals biomineralization, 259
263 CO2 dissolution and hydration chemistry, 254
256 mineral carbonation chemistry, 256
259 chemistry, 256
259 energy states of carbon, 256f

664

Mineral carbonation (Continued) heat released in carbonation reactions, 259t potential carbonation reaction routes, 259t Si2O5 sheet structure of phyllosilicate minerals, 257f structure of sheet silicate serpentine, 258f demonstration and deployment status, 276
281 coal gasification power plant with integrated mineral carbonation, 278
279 in situ carbonation, 279
281 steel mill with integrated mineral carbonation, 277
278 direct carbonation routes, 263
266 indirect carbonation routes, 266
268 storage by, 32 technology development status, 268
276, 269t alternative feedstocks and industrial integration, 271
272 design and development of demonstration-scale carbonation reactor, 275
276 disposal and reuse options for carbonation end products, 273
275 identification of preferred mineral feedstock, 269
271 reaction optimization, 272
273, 274t Minifrac tests, 323 Minimum kinetic diameter, 192
193 Mixed conducting medium (MCM), 97
98 Mixed conducting membranes. See Ion transport membranes Mixed electron carbonate conductor (MECC), 202 Mixed matrix membranes (MMMs), 198, 198f Mixed oxide carbonate conductor (MOCC), 202 MMMs. See Mixed matrix membranes (MMMs) MMV plan. See Measurement, Monitoring, and Verification plan (MMV plan) MnCr2O4. See Manganese
chromium (MnCr2O4)

Index

MOCC. See Mixed oxide carbonate conductor (MOCC) MOF. See Metal
organic frameworks (MOF) Mohr’s circle, and principal stresses, 321
322, 321f, 322f Mohr
Coulomb criterion, 327, 328f Molecular gate membranes, 203 Molecular sieves, 619 applications in oxyfuel combustion, 215
216 molecular sieving, 187
188, 192
195, 192f, 193t, 195t Molten salt extraction, 268 MOM. See Microbial organic matter (MOM) Monitoring plume movement, 456 Monitoring well construction, 417
418, 419t MONK project, 480 Monoethanolamine (MEA), 85, 116 Monte Carlo simulation, 298, 436, 450 Monterey Bay Aquarium Research Institute (MBARI), 525 Moving adsorption bed systems, 162
166 simulated moving beds, 164
165 Moving port chromatography, 164
165 MTR. See Membrane Technology Research (MTR) Multilateral wells, 409 Multivariate sensitivity method, 450 Mycorrhizal fungi, hyphal networks of, 550
551

N NADP. See Nicotinamide adenine dinucleotide phosphate (NADP) National Oceanic and Atmospheric Administration (NOAA), 6 National organizations and projects, 616
618 Natural Energy Laboratory of Hawaii Authority (NELHA), 531
532 Natural gas combustion, 26 firing, 51 membrane applications in, 220
224 gas
liquid membrane contactors, 222
224

Index

polymeric membranes, 221
222 processing, 110
111 treatment, 80
82 NBP. See Normal boiling point (NBP) NBZ. See Negative buoyancy zone (NBZ) Near-surface monitoring, 508
512 atmospheric monitoring, 508 geochemical leak detection in shallow aquifers, 510 offshore sonar monitoring, 512 plant health monitoring using reflectance spectra, 509
510 soil gas monitoring, 508
509 tracer injection, 510
512, 511t Negative buoyancy zone (NBZ), 529, 529f NELHA. See Natural Energy Laboratory of Hawaii Authority (NELHA) Nesquehonite (Mg(OH)(HCO3)  2H2O), 265 Net primary production (NPP), 10, 553
554 Nevada Desert FACE facility, 570t NF12 superalloy, 70t NF616 superalloy, 70t NF709 superalloy, 70t Nickel molybdate (NiMoO4), 109
110 Nicotinamide adenine dinucleotide phosphate (NADP), 544 Nitrates, 117
119 Nitrogen oxides (NOx), 39 control, 61 during combustion, 62 removal, 61, 80
82 electron beam flue gas, 63 by selective reduction, 62
63 Nitrous oxide (N2O), 534 NKn. See Knudsen umber (NKn) NOAA. See National Oceanic and Atmospheric Administration (NOAA) Non-Portland cement for CO2 service, 413 Non-corrosive gas, 425 Non-porous membranes, 195
196 Normal boiling point (NBP), 239
240, 240t, 246t Norsk Hydro/Alstom, 97
98, 98f North Sea CO2 network, 604
605 Novel sorbent materials, 177
178 composite sorbents, 178 high-temperature sorbents, 177
178 NPP. See Net primary production (NPP)

665

Nuon/Vattenfall IGCC plant, 79
80 “Nutraceuticals” systems, 585

O Ocean acidification, 3
4 afforestation, 538
539 alkalinity, 9 carbon cycle, 3, 518
523 biological pump, 522
523, 522f solubility pump, 519
522, 519f carbon inventory, 8, 8t global thermohaline circulation, 520f iron fertilization, 533
536 London convention impact assessment recommendation, 536t other fertilization options, 535 prospects for implementation, 535
536 results of iron fertilization trials, 533
535 long-term atmosphere
ocean CO2 equilibrium, 523 ocean storage of CO2, 524t ocean-floor CO2 lakes, 527
528 ocean-floor sediments, storage in, 529
530 temperature vs. depth in tropical ocean, 521f Ocean macroalgal afforestation (OMA), 538 Ocean Sequestration Field Experiment, 530
531, 531f Ocean storage, 30
31 biological sequestration, 533
539 chemical sequestration, 532
533 direct CO2 injection, 524
532 physical, chemical, and biological fundamentals ocean carbon cycle, 518
523 physical properties of CO2 in seawater, 517
518 Ocean storage field trials, large-scale, 530
532 OCGT. See Open-cycle gas turbine (OCGT) Offshore sonar monitoring, 512 Oil and gas reservoir exploitation, 471
472 Oil refining, 108
110, 109f Oil reservoirs, 29 Olivine ((Fex, Mg1
x)2SiO4), 32, 257

666

OMA. See Ocean macroalgal afforestation (OMA) OOIP. See Original oil in place (OOIP) Open-cycle gas turbine (OCGT), 64
65, 67 Optimum injection pressure, 451 well count, 451
452 well design, 452
453, 452t well location, 452 Ore hematite (Fe2O3), 107 Organic carbon, 558
559 Original oil in place (OOIP), 471 ORNL-FACE experiments, 568t Oxyfuel combustion, 28, 86
88, 86t cryogenic systems for, 245
247 membrane and molecular sieve applications in, 215
216 ion transport membranes for oxygen production, 216 molecular sieves for oxygen production, 216 oxyfuel RD&D projects, 87
88 Oxyfueling/oxyfuel, 26, 39
40, 75, 94, 105
106, 106t Oxygen, 86 enrichment, 105
106, 106t ion transport membranes for syngas production, 213
214, 214f oxygen-fired blast furnace, 108 production cryogenic, 245
247 ion transport membranes for, 216 molecular sieves for, 216 Oz FACE facility, 570t Ozone, 61
62

P P91 superalloy, 70t Palladium (Pd), 214
215 membranes in IGCC applications, 214
215 PAMAM. See Poly(amidoamine) (PAMAM) Partial oxidation (POX), 38
39 Particulate inorganic carbonate (PIC), 523 Particulate organic carbon (POC), 522 Passivation layer, 48 Passive seismic monitoring, 497
498 PBFB. See Pressurized bubbling fluidized bed (PBFB)

Index

PC. See Portland cement (PC) PCC. See Precipitated calcium carbonate (PCC) PCFB. See Pressurized circulating fluidized bed (PCFB) PCMs. See Phase-change materials (PCMs) PCOR. See Plains CO2 Reduction Partnership (PCOR) pdf. See Probability density function (pdf) PDMS. See Poly(dimethylsiloxane) (PDMS) Permeability of rock, 315
319 caprock permeability, 318 fracture permeability, 319 Frio “C” formation, 316f horizontal and vertical permeability, 316
318 processes affecting, 319 Perovskite, 202 Petra Nova capture project, 97 PFBC. See Pressurized fluidized bed combustion (PFBC) Phase-change functionalized MOF sorbents, 179
180, 180f solvent R&D bi-phasic liquid solvent R&D, 139
140 precipitating solvent R&D, 140 solvents, 122
123 Phase-change materials (PCMs), 154
155 Photobioreactor carbon delivery options, 588, 588f Photosynthesis, 31, 275, 522
523 aboveground and belowground carbon allocation, 547, 547t C3 photosynthesis, 544
546 C4 and CAM photosynthesis, 546
547 photosynthetic production, 6
7, 32 Physical absorption, 115, 123
125, 126t applications, 133
138 Fluor solvent process, 137
138, 137f Rectisol process, 136
137, 136f relative solvent loading of chemical and physical solvents, 133f Selexol process, 134
136 Physical adsorption, 151 adsorption
desorption isotherms, 154f chemical and physical adsorbents, 156
157, 156t, 157t sorbent working capacity for TSA and PSA, 153f

Index

sorption
desorption characteristics, 155
156 thermodynamics, 151
157 Physical pump. See Solubility pump Physical sorbents, 160
161 MOF, 161 zeolites, 160
161 Physisorption, 151 Phytoplankton, 523, 535 PIC. See Particulate inorganic carbonate (PIC) Pilot-scale testing, R&D and oxyfuel combustion, 87, 88t post-combustion capture, 84
85 pre-combustion capture, 78
80, 79t PIP test. See Produce
inject
produce test (PIP test) Pipe reactors, 275, 276f Pipeline corrosion, 598
599, 599t Pipeline engineering fundamentals flow assurance, 600
601 fluid flow, 596
598 pipeline and equipment materials issues, 598
600 materials issues, 600, 600t pipeline corrosion, 598
599 pipeline fracture failure, 599
600 Pipeline transportation, 595
606 case studies North Sea CO2 network, 604
605 Texas Gulf coast CO2 network, 603 pipeline engineering fundamentals, 596
601 pipeline operating considerations, 601, 601t, 602t RD&D for pipeline transportation in CCS projects, 605
606 systems, 602
603, 603f Piperazine (PZ), 119
120, 120f PKE. See Poludniowy Koncern Energetyczny SA (PKE) Plains CO2 Reduction Partnership (PCOR), 484 Plant chloroplast, 544 Plant health monitoring, 509
510 Platinum
rhenium catalyst, 109 Plume geothermal system, 30 PM-CAES. See Porous media compressed air storage (PM-CAES)

667

POC. See Particulate organic carbon (POC) Poiseuille’s equation, 189 Poludniowy Koncern Energetyczny SA (PKE), 70 Poly(amidoamine) (PAMAM), 203 Poly(dimethylsiloxane) (PDMS), 222 Polycarbonates, 577 Polymeric facilitated transport membranes, 222 Polymeric membranes, 196
197, 221
222 dual membrane module system, 222f hybrid membrane
distillation process, 221f polymeric facilitated transport membranes, 222 Polytetrafluoroethylene (PTFE), 202 Polyurethanes, 33 Polyvinylamine (PVAm), 220 Pore pressure, 320
324 measurement, 323
324 principal stresses and Mohr’s circle, 321
322 Poro-elastic stress. See In situ stress Porosity of rock, 314
315 measurement of porosity, 315 processes affecting, 319 total and effective porosity, 314 Porous media, single-phase flow in, 344
345 Porous media compressed air storage (PMCAES), 486 Porous membrane(s), 187, 188t transport processes, 188
195 Knudsen diffusion, 189
191, 190f molecular sieving, 192
195 surface diffusion and capillary condensation, 191
192 viscous capillary flow, 189, 190f Portland cement (PC), 103 additives, 413, 414t blocks, 580 Post-combustion approaches, 75 capture, 26, 80
86, 83t, 106 from cement plants, 104
105, 105t CO2 capture, 107 cryogenic separation, 243
244, 244f RD&D projects, 83
86 Potassium carbonate (K2CO3), 119, 160, 175

668

Potassium carbonate hydrotalcite-based sorbent, 108 Potassium chloride (KCl), 356
357 Potassium dawsonite (KAlCO3(OH)2), 176
177 Potassium hydroxide (KOH), 589 Power generation, 278 capture from, 23
27 combined cycle power generation, 63
68 developments in power generation technology, 68
70 materials development for SC and USC boilers, 69
70, 69f, 70t fossil-fueled power plants, 50
63, 50f physical and chemical fundamentals fossil fuel combustion, 37
40, 38t gasification of fossil and fuels, 40, 40t syngas production from methane, 40
41, 40t thermodynamic cycles, 41
47, 41f, 42f systems, 12, 33
35 Power-plant steam generators, 57 POX. See Partial oxidation (POX) Precipitated calcium carbonate (PCC), 577
579 steel mill with mineral carbonation of slag by direct air capture, 578 Precipitation, 49, 60
61 hardening, 49 precipitating solvent R&D, 140 precipitating systems, 122 Pre-combustion approaches, 75 capture, 26, 75
80, 77f, 77t cryogenic separation, 242
243 RD&D projects, 78
80 Pressure control strategies, 453 Pressure measurements, in CO2 flood monitoring, 477t Pressure swing adsorption (PSA), 153, 153f, 242
243 advanced PSA cycles, 171
173 adsorption heat storage, 172
173 high-frequency pressure cycling, 171 processes, 167
171 PSA cycle, 169
171, 172f VSA, 169
171 Pressure transients, pipeline system, 601t Pressurized bubbling fluidized bed (PBFB), 55
56

Index

Pressurized circulating fluidized bed (PCFB), 55
56 Pressurized fluidized bed combustion (PFBC), 65 Primary amines, 117 Primary cementation, 410 Primary energy-conversion efficiency, 13 Primary injection optimization approach, 450
453 Primary production, 523 Primer effect, 549
550 Principal stresses and Mohr’s circle, 321
322, 321f, 322f Probabilistic storage capacity estimation, 298
299, 298f Probability density function (pdf), 298 Produce
inject
produce test (PIP test), 513 Proline (C5H9NO2), 123 Propylene (C3H6), 109 Propylene carbonate (C4H6O3), 125, 137 PSA. See Pressure swing adsorption (PSA) PTFE. See Polytetrafluoroethylene (PTFE) Pulp and paper production, 111
112, 111f Pulverized fuel, 50
51 Push
pull test, 513, 513f PVAm. See Polyvinylamine (PVAm) P-wave velocity, 493 Pyrite (FeS), 373 PZ. See Piperazine (PZ) Q Quantifying and monitoring potential ecosystem impacts of geological carbon storage project (QICS project), 400 Quantitative risk assessment (QRA), 396 Quest MMV plan, 464 Quest storage development plan (Quest SDP), 461
463, 462t R Radial flow, 355
356 RAM. See Risk assessment matrix (RAM) Rankine cycle, 43
45, 44f, 45f, 51, 63
64, 68, 241 RCPs. See Reference Concentration Pathways (RCPs) RD&D, 69, 78 absorption technology, 138
147

Index

amine-based systems, 138
139 enzyme catalyzed aqueous carbonate solvent R&D, 139 IL solvents, 140
141 phase-change solvent R&D, 139
140 sodium hydroxide
based systems, 143
147 solvent microencapsulation, 141
143 adsorption technology adsorption-based DAC, 176
177 advanced PSA/VSA cycles, 171
173 chemical looping RD&D status, 180
183 MOF, 178
180 novel sorbent materials, 177
178 sorption-enhanced reactions, 173
176 in cryogenic and distillation technologies hydrate capture RD&D, 250 traditional cryogenic and distillation system RD&D, 249
250 membrane technology, 209
212, 209t, 210t oxyfuel combustion, 87
88 planned demonstration projects, 87
88, 89t R&D and pilot-scale testing, 87, 88t for pipeline transportation in CCS projects, 605
606, 606t post-combustion capture, 83
86 demonstration and early deployment projects, 85
86, 85t, 86f R&D and pilot-scale testing, 84
85, 84t pre-combustion capture, 78
80 demonstration and early deployment projects, 80, 81f, 82t R&D and pilot-scale testing, 78
80, 79t R&D in terrestrial carbon storage, 566
574 CSiTE terrestrial sequestration R&D program, 00021#s0150, 00021#t0050 FACE experiments, 566
572, 567f, 568t, 570t RDD&D. See Research, Development, Demonstration, and Deployment (RDD&D) RDF. See Refuse-derived fuel (RDF) Reaction optimization, mineral carbonation, 272
273, 274t

669

Reaction stage, steam turbine, 57
58 Reactive transport modeling of storage complex, 375
379 fluid flow consequences of geochemical FEP, 375
377 geomechanical consequences of geochemical FEP, 377
379 Reactive transport models, 375 Recalcitrant carbon, 550
551 Recovery, heat, 54
55 Rectification section, 229
230 Rectisol process, 136
137, 136f Recycled steel, 108 Redfield ratio, 535 Reference Concentration Pathways (RCPs), 13
14 Reflectance spectra, plant health monitoring using, 509
510 Reflection seismology, 489 Reflux steps, Skarstrom cycle, 168, 169t Reforestation, forestry, 564
565 Reforming catalytic, 109 catalytic steam, 41 chemical looping, 91
92 sorption-enhanced steam, 175
176 Refuse-derived fuel (RDF), 52 Regeneration, 47, 61, 92 Regional hydrological regime, 389
390, 389t Reheating, 53
54 Relative permeability, 345
358 fluid mobility and flood front stability, 352 formation drying effects, 356
357 imbibition and drainage processes, 352
355 radial flow, 355
356 Research, Development, Demonstration, and Deployment (RDD&D), 15 timescale, 15
19, 18f, 19t Research Fund for Coal and Steel (RFCS), 84
85 Residual oil fairways, 473
474 zone fairways, 473
474 Residual trapping, 351
357 of CO2, 290, 290f enhanced, 454 Retrofit power plant, 93
97

670

Retrofitting capture capability, 96
97, 96t, 97t Reuse options for carbonation end products, 273
275 Reverse Carnot cycles, 241
242 Reverse osmosis, 204 Reversible chemical reactions, 173 Reversible ILs, 141 Reynolds number, 596
597 RFCS. See Research Fund for Coal and Steel (RFCS) Risk assessment matrix (RAM), 401, 404f Risk management, 432t, 435, 436f Risk-based Environmental Management Plan, 401 ROAD. See Rotterdam Opslag en Afvang Demonstratieproject (ROAD) Rock compressibility, 324
325 facies, 309 failure criteria, 327, 328f formations, 305 impurities impact on, 358
362 on CO2 properties, 358
362, 359t on geological storage, 360
362 Rock
fluid interactions, 345 Rotating packed bed technology (RPB technology), 139 Rotterdam Opslag en Afvang Demonstratieproject (ROAD), 604
605 RPB technology. See Rotating packed bed technology (RPB technology) RuBisCO mechanism, 545
546 RWE Power company, 80 Ryan
Holmes process for CO2
CH4 separation, 247
249, 248f S S-waves. See Shear waves (S-waves) SACS. See Saline Aquifer CO2 Storage (SACS) Safety valves, upper well completion, 416 Saline aquifer brine properties brine density, 339
340, 340f brine viscosity, 340
341, 341f geological storage generic stage-gate project management process, 430f

Index

project stage, 430f SDP, 449
455 storage site assessment and selection, 441
448 storage site identification and screening, 429
441 R&D for, 467, 468t storage, 29
30 storage operations and monitoring, 455
460 case studies, 461
467 corrective measurement and remediation, 457
460 corrective pressure control strategies, 458
460 injection plan and storage capacity updates, 455
456 Ketzin Storage Pilot project, 467 monitoring plume movement, 456 Shell’s Quest project, 461
464 Statoil’s Sleipner project, 464
467 well injectivity monitoring, 456 well integrity monitoring and remediation, 457
458 trapping mechanisms indicative specific capacities of, 292
293, 293t time dependence of, 294 Saline Aquifer CO2 Storage (SACS), 461 Sandface completion, 414, 416, 416f, 453 SAR. See Synthetic aperture radar (SAR) Sarcosine (C3H7NO2), 123 SaskPower operated Boundary Dam capture project, 97 Saturation, algal biomass production systems, 586 SC. See Supercritical (SC) Schwarze Pumpe pilot plant, 15
19, 87 Scottish and Southern Energy (SSE), 482 SCR. See Selective catalytic reduction (SCR) SDM. See Surface deformation monitoring (SDM) SDP documents. See Storage development planning documents (SDP documents) Seabed monitoring, 508
512 geochemical leak detection in shallow aquifers, 510

Index

offshore sonar monitoring, 512 tracer injection, 510
512, 511t Seawater direct carbonation in, 265 physical properties of CO2 in, 517
518 hydrate formation and decomposition, 518 saturation pressure, 517 Secondary amines, 117 Secondary recovery methods, 471 Sedimentary processes, 305
306 Sediments, soils and, 398 Seismic surveys/surveying, 307, 489
498 AVO analysis, 494
495, 494f cross-well seismic, 496
497, 497f monitoring techniques for geological storage, 490t passive seismic monitoring, 497
498 time-lapse seismic monitoring, 493
494 VSP, 495
496, 495t, 496f Selective catalytic reduction (SCR), 62 Selective non-catalytic reduction process (SNCR process), 62
63 Selexol process, 77
80, 125, 134
136, 134t, 135f Sequestration chemical, 532
533 ocean, 621 planned EOR sequestration projects, 479 terrestrial ecosystem, 621 SER. See Sorption-enhanced reactor (SER) Serpentine (Mg3Si2O5(OH) )4), 32, 257 Shallow aquifers, geochemical leak detection in, 510 Shallow phreatic zone process, 390
391 Shear waves (S-waves), 492 Sheep Mountain pipeline, 602t Shell ADIP-X process, 131 Peterhead-Goldeneye project, 482 Quest project, 461
464 Quest MMV plan, 464 Quest SDP, 461
463, 462t Silicate rocks, 257 SILMs. See Supported ionic liquid membranes (SILMs) Silver (Ag), 214
215, 581 Simulated moving beds, 164
165, 164f Single-factor sensitivity analysis, 395, 450

671

Single-phase flow Darcy’s law, 344
345, 346t in porous media, 344
345 Site assessment risk, 446 Site characterization time-lapse seismic results, 466f Site uncertainty analysis, 446 Skarstrom cycle, 167, 167f, 168f, 170f, 170t Skymine process, 143, 143f Slag, mineral carbonation of by direct air capture, 578 Sleipner Field, 464
467 SLM. See Supported liquid membrane (SLM) Smart ILs. See Reversible ILs “Smart” cements, 413 SMR. See Steam methane reforming (SMR) SNCR process. See Selective non-catalytic reduction process (SNCR process) Snøhvit pipeline, 602t SOC. See Soil organic carbon (SOC) Sodium bicarbonate (Na2HCO3), 158 Sodium carbonate (Na2CO3), 158 Sodium hydroxide (NaOH), 28
29, 121, 589 extraction, 268 sodium hydroxide
based absorption, 121
122 sodium hydroxide
based systems, 143
147 direct air CO2 capture using sodium hydroxide, 144
147 flue gas CO2 capture using sodium hydroxide, 143
144 Sodium titanate cycle, direct air capture process using, 146f Sodium zirconate (Na2ZrO3), 177 SOFCs. See Solid oxide fuel cells (SOFCs) Soft tissues pump, 523 Soil organic carbon (SOC), 548
549, 558 Soil organic matter (SOM), 548 factors influencing physical protection of, 550t Soil(s) biogeochemical features and processes in, 548
551 factors increasing soil carbon stocks and related practices, 551t humification, 548
550

672

Soil(s) (Continued) macro-and microaggregate particles in soil, 551f soil microbiota, 548 soil structure, 550
551 biogeochemistry management, 558
559 biochar, 559 soil biogeochemistry R&D, 559 biogeochemistry R&D, 559 carbon inventory, 7, 8t carbonation in soils direct, 265
266 gas monitoring, 398, 508
509 respiration, 10 and sediments, 398 Solid oxide fuel cells (SOFCs), 98 Solubility pump, 8, 519
522, 519f trapping, 357
358 of CO2, 291 Solution
diffusion transport process, 195
197, 195f SOM. See Soil organic matter (SOM) Sonar measurements, 512 Sorption of organic molecules onto mineral surfaces, 558 sorption-enhanced reactions, 158
159, 173
176 sorption-enhanced steam reforming, 175
176 sorption
desorption characteristics, 155
156, 155t sorption-enhanced reactor (SER), 173
174 sorption-enhanced WGS (SEWGS), 173
175, 174f, 174t Soy FACE facility, 570t Special Report on Emissions Scenarios (SRES), 12
13 Spirulina, 585 Sporosarcina pasteurii (S. pasteurii), 427 Spray attemperator, 54 Spray-tower system, 28
29 Squeeze cementation, 411 SRB. See Sulfate-reducing bacteria (SRB) SRES. See Special Report on Emissions Scenarios (SRES) SSE. See Scottish and Southern Energy (SSE)

Index

Stage-gate project management process, 429 Static reservoir model, 319, 320t Static trapping, 288
289 Static traps. See Structural trapping Statoil’s Sleipner project, 461, 464
467, 465f injection operation and monitoring, 465
467, 466f site characterization and selection, 464
465 Steam cycle, 65 generation, 52
57 boiler technology, 53
56 SC and USC steam operation, 57 generators, 42 steam-side oxidation resistance, 57 temperature, 47, 53
54, 57, 68 turbine technology, 57
59, 58f, 59f velocity, 57 Steam injected gas turbine (STIG), 47 Steam methane reforming (SMR), 168
169 Steel(s), 49
50, 70t corrosion resistance, 48 metallurgy for fossil-fueled power plants, 47
50, 48t mill with integrated mineral carbonation, 277
278, 278f with mineral carbonation of slag, 578 production, 107
108 Steric hindrance, 117 STIG. See Steam injected gas turbine (STIG) Stirling cooling cycle, 241, 242f Storage capacity classification, 294
296 GCS capacity, 295t storage complex, 305, 306t technical limits, 476
478 updates, 455
456 Storage development planning (SDP), 441
444, 449
455 optimum injection pressure, 451 pressure control strategies, 453 primary injection optimization approach, 450
453 trapping control strategies, 454
455 Storage efficiency, 296 Storage formation

Index

and caprock heterogeneity, 309
314 caprock stratigraphy, 310 fracture systems, 310
314 stratigraphy, 309
310 and caprock properties permeability, 315
319 porosity, 314
315 processes affecting porosity and permeability, 319 static reservoir model, 319, 320t type and geometry, 305
314 faulting, 307
308 open, partially open, and closed systems, 308 and overburden structure, 306
308 sedimentary processes, 305
306 Storage monitoring and verification technologies gravity and electromagnetic surveys, 499
503 ground surface deformation monitoring, 503
507 injection-withdrawal tests, 513
514 seismic surveying, 489
498 surface, near-surface, and seabed monitoring, 508
512 Storage site assessment and selection, 441
448 modeling workplan execution, 445
446 optimization criteria for storage planning, 448, 449t preparing initial monitoring plan, 446
447, 447f, 448f site assessment risk and uncertainty analysis, 446 Storage site identification and screening, 429
441 analyze data and perform site screening, 431 storage site screening criteria, 432t, 435f defining storage site selection criteria, 441 elements of site assessment and selection workplan, 444t technical site selection criteria, 442t obtain data and identify prospective sites, 429
431 process steps, 430f

673

ranking and shortlisting of potential sites, 436
440 screening stage risk assessment, 435
436 early-stage risk register for a GS project, 437t GS project risk management framework, 436f screening stage uncertainty assessment, 431
435 workplan for storage site assessment and selection, 441 Storativity (S), 388 Stratigraphy, 309
310 process, 306 stratigraphic trap, 286
289, 309 time-lapse seismic, 310f Stress, in situ, 320
324 orientation and magnitude, determination of, 322
323 pore pressure measurement, 323
324 principal stresses and Mohr’s circle, 321
322 Structural trapping, 286
289 Subcooled liquid transportation, 597
598 Subcritical boiler, 53 Subsea CSEMs, 501
502 Subsurface microbial recycling of CO2, 383
384 Sulfate-reducing bacteria (SRB), 379 Sulfates, 117
119 Sulfur atoms, 109
110 Sulfur dioxide (SO2), 59
60 Sulfur hexafluoride (SF6), 508, 534 Sulfur trioxide (SO3), 59
60 Sulfuric acid, 61, 109 Superalloys, 70t Supercritical (SC), 42 boilers, materials development for, 69
70, 69f fluid, 31 plants, 63 steam cycle, 44
45 steam operation, 57 Superheating, 44, 53
54 Supported ionic liquid membranes (SILMs), 202 Supported liquid membrane (SLM), 199f, 202
203

674

Surface coating, 584 Surface CSEMs, 501
502 Surface deformation monitoring (SDM), 490t, 505t Surface diffusion, 191
192, 192f Surface gas monitoring, 398 Surface monitoring, 395
396, 508
512 atmospheric monitoring, 508 geochemical leak detection in shallow aquifers, 510 offshore sonar monitoring, 512 plant health monitoring using reflectance spectra, 509
510 soil gas monitoring, 508
509 tracer injection, 510
512, 511t Surface temperature, of earth, 3, 4f Surface topography, 396
397 Surface water bodies, 397
398 Surface-modified porous media, 156t Surfactant molecules, 235 SwedFACE experiments, 568t Switchable ILs. See Reversible ILs Switchgrass, 573 Synthesis gas (Syngas), 40, 52, 88
89, 91
92, 278 oxidation, 92
93 production, 202, 213
214 production from methane, 40
41 Synthetic aperture radar (SAR), 503
507 T Task-specific ionic liquids (TSILs), 141 TASR. See Total accessible storage resource (TASR) TBS. See Thermomorphic bi-phasic solvents (TBS) TCM. See Test Centre Mongstad (TCM) Techno-Economic Resource-Reserve Pyramid for CO2 Storage Capacity, 295, 296f Technology Readiness Level classification (TRL classification), 15, 17t Temperature conditions, CO2 carriers, 607 dependence of CO2 solubility in methanol, 124f earth surface, 3, 4f steam temperature control, 53
54 Temperature swing adsorption (TSA), 153, 153f

Index

ESA, 167 TSA/desorption, 166
167 Temperature
entropy diagram (T-S diagram), 41 Brayton gas turbine cycle, 46f, 47f Carnot thermodynamic cycle, 42f Rankine cycle heat engine, 44f superheated, reheated, and SC steam cycles, 45f for water, 41f Tensile strength of rock, 325, 325t Terrestrial carbon cycle, 3 inventory, 7, 32 storage options, 554
565 agricultural carbon storage, 555
561 changes in land use, 561
565 Terrestrial ecosystem(s), 543 biological and chemical fundamentals, 544
554 biogeochemical features and processes in soils, 548
551 modeling climate
ecosystem interactions, 552
554 photosynthesis, 544
547 carbon storage in, 543 full GHG accounting for terrestrial storage, 565
566 R&D in terrestrial carbon storage, 566
574 sequestration, 621 storage in, 31
32 terrestrial carbon storage options, 554
565 Tertiary amines, 116
117 Test Centre Mongstad (TCM), 85
86 Tetrahydrofuran (THF), 234 Texas Gulf coast CO2 network, 603, 604t Theoretical storage capacity, 288 Thermal efficiency, 23, 39, 47, 54 of boiler, 54 of Carnot cycle, 63
64 combined cycle, 66
67 of conventional power plants, 63, 63t power plant, 63t Thermo-elastic stress, 326 Thermocline, 520
521 Thermodynamic cycles, 37, 41
47, 41f, 42f Brayton gas turbine cycle, 45
47, 46f, 47f Rankine steam cycle, 43
45, 44f, 45f

Index

Thermohaline circulation, 8 Thermomorphic bi-phasic solvents (TBS), 123 THF. See Tetrahydrofuran (THF) Thorium-234 (234Th), 534 3D seismic surveys, 456 3D simulation models, 317 Tidal salt marshes, 561
562 Tight oil reservoir CO2-EOR, 474 Tiltmeters, 490t, 507 Time-lapse 3D seismic surveys, 456, 490t CO2 flood monitoring, 477t saline aquifer storage, 493
494 seismic monitoring, 493
494 Titanate cycle, 122 Total accessible storage resource (TASR), 296 Tracer injection, 510
512, 511t Transesterification, 589, 589f Transition metals, 89
90 Transportation systems, 622 Trapping control strategies, 454
455 accelerated solubility trapping, 454
455, 455f enhanced residual trapping, 454 Trapping mechanisms, 468t Tri-calcium silicates (3CaO  SiO2), 412 Triglyceride, 589, 589f Triple-pressure HRSG, 66, 66f, 67t TRL classification. See Technology Readiness Level classification (TRL classification) T-S diagram. See Temperature
entropy diagram (T-S diagram) TSA. See Temperature swing adsorption (TSA) TSILs. See Task-specific ionic liquids (TSILs) Tubing, CO2 impact on, 425 U Ultramafic rocks, 257 Ultrasonic agitation, 273 Ultrasupercritical conditions (USC conditions), 42 Unconformity, 306
307 Under-reaming operation, 421 Underbalanced drilling technique, 408

675

Underground sources of drinking water (USDW), 410
411 United States, organizations and projects in, 616
618 Units, CCS, 625 Upgrading, 109
110 Upper completion, wells, 414, 416, 417f Urea, 33, 382, 577 Ureolytic bacteria, 262 US DOE’s SEQURE tracer technology project, 512 USC boilers, materials development for, 69
70, 69f USC conditions. See Ultrasupercritical conditions (USC conditions) USC steam operation, 57 USDW. See Underground sources of drinking water (USDW) Utsira aquifer, 111, 309
310, 310f, 345, 350
351, 369, 409, 459, 464, 466
467

V Vacuum and pressure swing adsorption cycle (VPSA cycle), 169
171 Vacuum swing adsorption (VSA), 169
171 advanced VSA cycles, 171
173 adsorption heat storage, 172
173 two-bed air separation unit using Guerin
Domine cycle, 171f Vadose zone process, 390
391 Valance band (VB), 582 Vapor compression, 241, 241f Vapor phase vapor
liquid distribution ratio, 227
228 water
CO2 vapor phase properties, 344 Vapor pressure, 248f Vapor
liquid distribution ratio, 227
228 equilibrium, 123, 230 Variable density log (VDL), 411 Vattenfall AB oxyfuel project, 87 VB. See Valance band (VB) VDL. See Variable density log (VDL) Vegetation and terrestrial fauna, 396 Venting, 30
31 VERA. See Vertical electrical resistivity array (VERA)

676

Verification of CO2 movement, 475
476 Vertical electrical resistivity array (VERA), 418 Vertical permeability (kv), 316
318, 318f Vertical seismic profiling (VSP), 490t, 495
496 Vertical wells, 409 VFAs. See Volatile fatty acids (VFAs) Viscous capillary flow, 189, 190f Volatile fatty acids (VFAs), 379 Volatility, of liquids, 227
228 Volume measurements, in CO2 flood monitoring, 477t VPDB carbonate standard, 547 VPSA cycle. See Vacuum and pressure swing adsorption cycle (VPSA cycle) VSA. See Vacuum swing adsorption (VSA) VSP. See Vertical seismic profiling (VSP) W WAG scheme. See Water-alternate-gas scheme (WAG scheme) Wallula basalt injection pilot, 279
280 Wastes, as feedstock for mineral carbonation, 32 Water freezing temperature, 42 solubility in CO2, 342 wall, 53 water
CO2 vapor phase properties, 344 Water-alternate-gas scheme (WAG scheme), 473 Water
gas shift membrane reactor (WGSMR), 214
215, 215f Water
gas shift reaction (WGS reaction), 41, 75, 78, 80, 168
169, 273 Wave-driven ocean upwelling, 537, 537f Well completion and control, 413
418 construction and status, 407
421 Well abandonment, 419
421, 420f Well cementation, 410
413 cement evaluation logging tool results, 411f characteristics of API cement classes, 412t non-Portland cement for CO2 service, 413 Portland cement additives, 413, 414t types and composition of well construction cement, 412

Index

Well construction data gathering in wells, 413, 415t monitoring well construction, 417
418, 419t and status, 407
421 well completion and control, 413
418 well design, 407 well drilling and casing, 407
409, 409f well operations, 418
419 Well injectivity monitoring, 456 Well integrity cement barrier defects, 422f, 422t CO2 impact on casing and tubing, 425 CO2 impact on cement, 423
425 CO2 impact stream impurities on, 425 geology impact on, 426 monitoring and remediation, 457
458 processes affecting, 421
426 Well remediation, 426
427 abandoned wells, 426 cement remediation by biomineralization, 427 implications for site selection and monitoring, 427 injection and monitoring wells, 426
427 Wet scrubbing flue gas desulfurization process, 60
61 electron beam FGD, 61 Wet-bottom furnace, 59 Wetland management and restoration, 561
562, 563t Wettability, 345
347 Weyburn, passive seismic, 498, 498f Weyburn CO2 monitoring and storage project, 301t, 302t, 303t Weyburn field, EnCana, 474
479 geological characterization, 475 WGS reaction. See Water
gas shift reaction (WGS reaction) WGSMR. See Water
gas shift membrane reactor (WGSMR) Wollastonite (CaSiO3), 32, 257 Working capacity (Δ) of sorbent, 153, 153f, 155t, 180f X “Xmas tree”, well, 416 X-ray diffraction techniques (XRD techniques), 374

Index

Z Zeolites, 156t, 160
161, 160f, 204 Zeolitic imidazolate frameworks (ZIFs), 161, 198 Zero Emission Coal Alliance (ZECA), 98 Zero emission power generation (ZEP generation), 97
100

677

AZEP, 97
98, 98f ZEC, 98
100, 99f, 99t Zero-emission coal concept (ZEC concept), 98
100, 99f, 99t Zero-emission integrated gasification combined cycle (ZEIGCC), 78, 79t Zwitterion, 200