Drilling Engineering: Towards Achieving Total Sustainability 9780128201930, 0128201932

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DRILLING ENGINEERING TOWARDS ACHIEVING TOTAL SUSTAINABILITY M. RAFIQUL ISLAM M. ENAMUL HOSSAIN

Gulf Professional Publishing is an imprint of Elsevier 50 Hampshire Street, 5th Floor, Cambridge, MA 02139, United States The Boulevard, Langford Lane, Kidlington, Oxford, OX5 1GB, United Kingdom Copyright © 2021 Elsevier Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the publisher. Details on how to seek permission, further information about the Publisher’s permissions policies and our arrangements with organizations such as the Copyright Clearance Center and the Copyright Licensing Agency, can be found at our website: www.elsevier.com/permissions. This book and the individual contributions contained in it are protected under copyright by the Publisher (other than as may be noted herein). Notices Knowledge and best practice in this field are constantly changing. As new research and experience broaden our understanding, changes in research methods, professional practices, or medical treatment may become necessary. Practitioners and researchers must always rely on their own experience and knowledge in evaluating and using any information, methods, compounds, or experiments described herein. In using such information or methods they should be mindful of their own safety and the safety of others, including parties for whom they have a professional responsibility. To the fullest extent of the law, neither the Publisher nor the authors, contributors, or editors, assume any liability for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions, or ideas contained in the material herein. Library of Congress Cataloging-in-Publication Data A catalog record for this book is available from the Library of Congress British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library ISBN: 978-0-12-820193-0 For information on all Gulf Professional Publishing publications visit our website at https://www.elsevier.com/books-and-journals

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Preface created the most spectacular feats in technology, had to inhale toxic fumes emerging as a byproduct of their engineering. Those ancient technologies had no toxic outcome. Today, we have millions of technologies but none can claim such an outcome. Have we digressed in the last few millennia so much that now we cannot fathom anything beyond minimizing toxic shock? This book takes up the daunting task of introducing most recent advancements in petroleum drilling engineering and identifying areas that need more work to move toward sustainability. It is daunting because, for decades, the term “petroleum sustainability” has been mocked as an oxymoron. For the vast majority of “experts,” petroleum is inherently unsustainable and to the amazement of a logical mind, even oil company CEOs agree. The book doesn’t attempt to indoctrinate, doesn’t pontificate, doesn’t offer a salvation, and frankly, it would be a miracle if there is anyone sold to the idea of sustainable drilling practices. What it guarantees, however, is there is no logical argument that can be made against true sustainability using petroleum resources. There is no way a logical mind will ignore the message. In that sense, this book will truly bring about a paradigm shift.

For centuries, fossil fuels (starting with coals, followed by the petroleum golden era) have been the driver of energy needs of the modern civilization. Yet, during the past few decades, there has been an unwarranted hysteria against the use of fossil fuel (Islam and Khan, The Science of Climate Change, Scrivener-Wiley, 2019). And, the justification for such attack on fossil fuel: it’s carbon, Carbon the enemydthe same carbon that is the building block of all living organisms. Meanwhile, the “colonization of Mars” project is at full throttle because of the fear that the Earth will soon become inhabitable. Such lunacy is unprecedented in the history of humanity. In this modern era that brags about being ruled by the most evolved version of the species, Homo sapiens, everything seems to be a paradox. When it comes to settling theses paradoxes with logical answers, every scientist seems to be puzzled, and when scientists finally attempt to answer, they keep contradicting each other, no matter what the research question is or what the data indicate. Yet, all these “technological disasters” (in the words of Nobel laureate Chemist, Robert Curl) are phenomena of the plastic era, which is barely a century old. In no time, the pharaohs, who showed miraculous technological prowess, suffered from toxic shock of the chemicals they used. In no time those mountain-curved palace dwellers of Petra Valley or the Thamud, who

M.E. Hossain M.R. Islam

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C H A P T E R

1 Introduction 1.1 Introduction of the book Not long ago, any sustainable operation in the context of petroleum engineering was considered to be an absurd notion (Khan and Islam, 2007). Even today, the way the term “sustainability” is used it makes it difficult to talk about petroleum operations and sustainability in the same vein. From the 1973 Arab oil embargo onward, when cheap oil became a thing of the past, there has been a sustained campaign against fossil fuel in general and oil and gas in particular. Then came Al Gore’s “saving the planet from Carbon” awakening. The Greenpeace movement designated carbon as an existential threat to the current civilization. Meanwhile, Enrondthe most “innovative energy management” companydturned out to be a fraud. Even Republican president, George, chimed in to castigate humanity with the “oil addiction” line. That “Carbon is the enemy” mantra spread like wildfire and imposing universal carbon tax reached global pitch. Up until today, the world is convinced that petroleum consumption should be minimized, the oil price should be low, and replacement of petroleum should be subsidized. So, what is left for petroleum engineers to do other than folding shops and hiding behind an alternate fuel “wall”? If it were not for the opening up of unconventional oil and gas that gave rise to unprecedented surge in oil and gas production in the United States and equally important surge in global reserve in terms of heavy oil and tar sand, no book on sustainable petroleum drilling would see the light of the day. It is because of this unprecedented surge in petroleum activities, along with renewed focus on environmental sustainability, that a book of current title is necessary and timely. Drilling being the most important and likely the costliest part of a petroleum operation, sustainability must begin with drilling. This book is about rendering drilling operations sustainable. This book will be useful for both the energy sector and the environmental restoration/remediation sector. Drilling is the most important component of any mineral extraction (Marjoribanks, 2010). The advancement in drilling activities has literally catapulted the latest surge in petroleum drilling and production activities. Starting from the 1980s, horizontal wells became the most lucrative component of modern-day innovation. Added to that advancement is the marvel of drilling technology in deep oceans, in unconventional formations, and previously unexplored areas. The challenge, however, is to render drilling activities into sustainable ones. Considering that practically all disciplines are involved in a drilling operation, ranging from creating a drilling space within an environmentally sensitive area and using toxic

Drilling Engineering https://doi.org/10.1016/B978-0-12-820193-0.00001-0

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© 2021 Elsevier Inc. All rights reserved.

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drilling mud to drilling through vulnerable layers underground and disposing of toxic chemicals in an environmentally acceptable manner, greening of drilling technology can revolutionize the entire discipline of petroleum engineering. This in turn can cause ripple effect on other disciplines (Hossain and Abdulaziz Abdullah Al-Majed, 2015). The conventional approach to sustainability places the “three pillars of sustainability” (economy, society, and environment) in competition with each other (Scott Cato, 2009). Long-term sustainability lies with creating synergy rather than competition (Speight and Islam, 2016). The long-term sustainability approach is taken up in this book. Because the topic of sustainability is new in the context of petroleum engineering, this book will focus on topics that will become both relevant and pivotal in years to come. Past experiences would be critically analyzed to summarize the salient features of sustainability and areas of improvement. The book does not offer a paradigm shift in terms of content but offers a futuristic focus that has eluded previous authors. As such, this is a unique undertaking with tremendous ramifications.

1.2 Introduction to drilling engineering Modern civilization is driven by our energy needs. Despite controversies surrounding petroleum operations and their impact on the environment, petroleum resources continue to carry bulk of our energy needs. Sustainable development can alleviate environmental impacts and place petroleum operations on a leadership position even for environmental integrity and long-term sustainability (Islam and Khan, 2019). Drilling is the primary operation that connects us to the petroleum resources. As such, it is the most important operation. This technology is a necessary step for both petroleum exploration and production. While drilling engineering is a well-established discipline, the fact that every well is unique makes a drilling operation risky. In the past, risk management due to blow out concerns and safety of personnel has been the primary focus of a drilling operation. Over the last few decades, the concerns over environmental integrity and carbon footprint have overwhelmed petroleum operators. The challenge has been to drill faster, with greater precision in more hazardous areas or more technically challenging depths with minimum environmental damage than ever before. While the background work of planning, involving rock/fluid characterization, environmental impact assessment, and others, is a team endeavor, the execution of drilling is the responsibility of the drilling engineer. Drilling petroleum wells continues to be the most daunting task among all engineering undertakings. The most important aspect of preparing the well plan and subsequent drilling engineering determine the expected characteristics and problems to be encountered in the well. A well cannot be planned properly if these environments are unknown. Therefore, the drilling engineer must initially pursue various types of data to gain insight used to develop the projected drilling conditions.

1.2.1 Importance of sustainability and need of research It is well known that the petroleum industry drives the energy sector, which in turn drives the modern civilization. The present modern civilization is based on energy and hydrocarbon resources. The growth of human civilization and necessities of livelihood with time inspired human beings to bore a hole for different reasons (such as drinking water, agriculture,

1.3 Emerging technologies in drilling engineering

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hydrocarbon extraction for lighting, power generation, to assemble different mechanical parts). With recent awareness of environmental sustainability, it has become clear that most of our technological advances are in fact a quick fix of problems that arose from practices that shouldn’t have been commenced to begin with. At the risk of being labeled an anarchist, it is only proper to say, this fear has been shared by some of the most noncontroversial engineers and scientists (Nobel Laureate Chemist, Robert Curl, for instance). In this era of technological advancement being later labeled as “technological disaster,” drilling technologies bring in a silver lining. The advancements made in drilling technologies have been phenomenal and mark one of the proudest moments of the petroleum industry. Unfortunately, whenever disasters strike, the blame game begins and everyone rushes to disavow modern technology. With the spectacular failure of the Deep water horizon project in 2010, many questioned the validity of modern drilling advances, particularly in the areas of offshore drilling. Lost in that hysteria was the fact that research that fueled the instant solutions sought during that fateful drilling operation was in fact flawed. After the dust settled, however, the tragic event established one fact: there has to be systematic long-term research that addresses short-term problems with long-term solutions (Hossain and Islam, 2018). Drilling technologies are interconnected and involve practically all aspects of engineering, including material engineering, biomedical engineering, and communication. It is impossible to consider drilling problems as isolated projects. Drilling technology is a widely used expertise in the applied sciences and engineering, such as manufacturing industries, pharmaceutical industries, aerospace, military defense, research laboratories, and any small-scale laboratory to a heavy industry like petroleum. This book is the first of its kind that addresses existing problems and presents sustainable solutions, some of which would require further research. The book doesn’t compromise the relevance or scientific details in responding to most difficult questions arising from sustainability considerations. Rather than giving a technician’s response or a quick fix, it gives a researcher’s response with backing of field engineers with decades of experience. It further elucidates with citations of emerging technologies or even technologies that still are at a research level.

1.3 Emerging technologies in drilling engineering The last few decades of the last century were marked by a downtime for the petroleum industry. It was mainly because of low oil prices and resetting the technological focus away from fossil fuel (Islam, 2020). Even then, great strides were made in all sectors of petroleum engineering. Principal developments in the last decade of the 20th century were (Khan and Islam, 2007): • casing drilling technologies (including casing while drilling, casing running tool, drilling with casing; high performance casing); • rotary steerable tool (including rotary steering system, platform stabilization); • downhole equipment (particularly useful for directional drilling); • measurement while drilling (MWD); • expandable casing technology (particularly suitable for complex formations with unpredictable rock characteristics);

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• positive displacement motor technologies (amenable to sustainable energy consumption); • casing technologies (including expandable tubulars, casing drilling, reaming shoes, friction and drag reduction tools). Most of the above technologies have advanced offshore drilling capabilities to a great extent. The fruit of these technological advancements have been borne in the new millennium, with unprecedented speed and flexibility achieved in drilling unconventional formations and stimulation operations. Overall, drilling capabilities have been extended beyond 30,000 ft as a matter of routine. In terms of new drilling technology, the sonic drilling technology is worth a mention. In 1997, the Versa-Sonic drill rig was put into operation. This patented technology (Barrow, 1996) uses sonic vibration at a resonant frequency and brings in the possibility of drilling without drilling mud. This was an excellent addition to the technologies that would define the theme in the new millennium. In the new millennium, the focus has moved to “greening” of drilling fluids, zero-waste engineering, and sustainable developments (Hossain and Abdulaziz Abdullah Al-Majed, 2015). Advances in the monitoring technologies, along with special tools suitable for increasing production and recovery from unconventional reservoirs, have been at the forefront of drilling technology innovation in the new millennium. The biggest beneficiary of this technological feat has been the unconventional reservoirs. For instance, there has been an exponential growth in crude oil and gas productions from shale formations that jumped from a mere 2% in 2001 to over 40% of US crude oil and natural gas production in recent years. Patents issued often indicate trends for the upcoming decades. In the petroleum industry, hydraulic fracturing have gained the most prominence, with well over 1000 hydraulic fracturingerelated patents in the new millennium with ever increasing rates. For instance, under 75 patents were issued in 2015; with the pace of filing increasing year over year since 2006. In 2015, for example, these companies filed over 150 patents, more than double the number in 2006 (Deloitte, n.d). The majority of the fracturing-related patents lie in the (a) earth drilling category (E21B43, patent classification code), followed by (b) drilling compositions and related aspects (C09K8, C09K2208) and (c) well treatment and oilfield chemistry (Y10S507, Y10T428). The following two categories emerge: (i) Tools and methods to create effective fractures (increasing penetration, isolating zones, seismic monitoring, well treating, etc.), and (ii) Technologies and solutions that reinforce the already created fractures (different materials, shapes, and sizes of proppants; preventing flowback of particles, etc.). In each of these categories, the new focus has been to address environmental concerns. For instance, when it comes to selecting fracturing fluids, organic materials are being sought in order to sustainably control fluid loss and achieve viscosity reduction and system stabilization. Similarly drilling mud based on natural chemicals are being patented (Hossain, 2018; Hossain and Wajheeuddin, 2017).

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Overall, there is a crossroads after 2009, prior to which the main innovations focused on viscosity reduction and performance improvement through new additives and particulates. After 2009, the focus has shifted toward fluid treatment systems and increasing fracture complexity. In this later technological thrust, there is an opportunity to introduce new generation of technologies to steer oil and gas drilling and stimulation toward sustainable operations. In the new millennium, innovations in materials science as well as information technology have been the driver of technological trends. Innovations in metalworking in areas extend from drillstem to other technologies involving petroleum drilling operations, including gas turbine plants, nonpositive displacement machines, and nonpositive displacement pumps. For drilling engineering applications, it meant innovations in metalworks as well as monitoring tools, which can add synergy to the overall growth in efficiency, and eventually sustainability. In this process of technology development, bridging technologies play a crucial role. The petroleum industry in general and the drilling industry in particular have been the pioneers of developing bridging technologies. For well over half a century, the petroleum industry fostered partnerships with universities and other academic research organizations in order to develop bridging technologies into commercialized products. Technology bridging has become a popular theme at the dawn of the Information age (Chai and Shih, 2016). Irrespective of their sizes, these technologies represent key strategic “bridges” of intellectual property that connect back to the singularly important task of the major thrust (drilling in our case) drilling. As we will see in the next section, if a given drilling technology is not sustainable, bridging technologies must be treated as “technological pressure points” in changing the course of sustainability. Advancements in drilling technology moved rapidly in 5 years, as 16,000-foot wells were taking an average of 32 days to drill. By 2013, the average drill time for 21,000-foot wells was 18 days or less. Drilling methods continue to evolve to create wellbore for environments with pore pressure and fracture gradient issues resulting in tight drilling windows. Hess uses enabling technologies such as underbalanced, managed pressure and air drilling with low rheology drilling muds and cements to improve wellbore pressure control and drilling optimization. Equipment reliability is a cornerstone of drilling and completion performance. Hess’ quality assurance program partners with contractors to align objectives and expectations to create a clear plan for controlled equipment deployment in the field. Continuous improvement methodology ensures the overall service delivery processes are actively assessed for opportunities based on industry performance data. This approach ensures reliability can be planned into the business while managing the reactive aspects inherent in well operations. Operators face the challenge of engineering and integrating these capabilities into a well design for operation teams to deliver. A robust well delivery process organizes the technical work and leverages past learning to find the best engineering solutions to maximize the value of the well.

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1.4 Sustainability analysis of current drilling technologies Until now, there is no suitable alternative to fossil fuel and all trends indicate continued dominance of the petroleum industry in the foreseeable future (Islam and Khan, 2019). Even though petroleum operations have been based on solid scientific excellence and engineering marvels, only recently it has been discovered that many of the practices are not environmentally sustainable. Practically all activities of hydrocarbon operations are accompanied by undesirable discharges of liquid, solid, and gaseous wastes (Khan and Islam, 2007), which have enormous impacts on the environment (Islam et al., 2010). Hence, reducing environmental impact is the most pressing issue today and many environmentalist groups are calling for curtailing petroleum operations altogether. Even though there is no appropriate tool or guidelines available in achieving sustainability in this sector, there are numerous studies that criticize the petroleum sector and attempt to curtail petroleum activities (Holdway, 2002). There is clearly a need to develop a new management approach in hydrocarbon operations. The new approach should be environmentally acceptable, economically profitable, and socially responsible. The crude oil is truly a nontoxic, natural, and biodegradable product, but the way it is refined is responsible for all the problems created by fossil fuel utilization. The refined oil is hard to biodegrade and is toxic to all living objects. Refining crude oil and processing natural gas use large amount of toxic chemicals and catalysts including heavy metals. These heavy metals contaminate the end products and are burnt along with the fuels producing various toxic byproducts. The pathways of these toxic chemicals and catalysts show that they severely affect the environment and public health. The use of toxic catalysts creates many environmental effects that make irreversible damage to the global ecosystem. Similarly, the use of synthetic chemicals can render a drilling operation as well enhanced oil recovery operation unsustainable (Islam, 2020). Crude oil is a naturally occurring liquid found in formations in the Earth consisting of a complex mixture of hydrocarbons consisting of various lengths. It contains mainly four groups of hydrocarbons, among which saturated hydrocarbons consist of straight chain of carbon atoms, aromatics consist of ring chains, asphaltenes consist of complex polycyclic hydrocarbons with complicated carbon rings, and other compounds mostly are of nitrogen, sulfur, and oxygen. It is believed that crude oil and natural gas are the products of huge overburden pressure and heating of organic materials over millions of years. Crude oil and natural gases are formed as a result of the compression and heating of ancient organic materials over a long period of time. Oil, gas, and coal are formed from the remains of zooplankton, algae, terrestrial plants, and other organic matters after exposure to heavy pressure and temperature of Earth. These organic materials are chemically changed to kerogen. With more heat and pressure along with bacterial activities, oil and gas are formed. Fig. 1.1. is the pathway of crude oil and gas formation. These processes are all driven by natural forces. Sustainable petroleum operations development requires a sustainable supply of clean and affordable energy resources that do not cause negative environmental, economic, and social consequences (Dincer and Rosen, 2004, 2005). In addition, it should consider a holistic approach where the whole system will be considered instead of just one sector at a time (Islam et al., 2010). In 2007, Khan and Islam developed an innovative criterion for achieving

1.4 Sustainability analysis of current drilling technologies

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Biomass Decay and degradaon

Natural processes

Burial inside earth and ocean floors for millions of years Kerogen formaon

Bacterial acon, heat, and pressure Bitumen, crude oil and gas formaon

FIGURE 1.1

Crude oil formation pathway. After Chhetri and Islam, 2008.

true sustainability in technological development. New technology should have the potential to be efficient and functional far into the future in order to ensure true sustainability. Sustainable development is seen as having four elementsdeconomic, social, environmental, and technological. Different phases of petroleum operations which are seismic, drilling, production, transportation and processing, and decommissioning, as well as their associated wastes generation and energy consumption. Various types of waste from ships, emission of CO2, human related waste, drilling mud, produced water, radioactive materials, oil spills, release of injected chemicals, toxic release used as corrosion inhibitors, metals and scraps, flares, etc., are produced during the petroleum operations. Drilling is a necessary step for petroleum exploration and production. The conventional rotary drilling technique falls short, since it is costly and contaminates surrounding rock and water due to the use of toxic components in the drilling fluids. Conventional rotary drilling has been the main technique used for drilling in the oil and gas industry. However, this method has showed its limits regarding the depth of the wells drilled, in addition to the use of toxic components in drilling fluids. The success of a high-risk hydrocarbon exploration and production depends on the use of appropriate technologies. Therefore, to overcome the limitations of conventional rotary drilling technique, we need to look for other environmentally friendly drilling technologies, which may lead to a sustainable drilling operation. Generally, a technology is selected based on criteria such as technical feasibility, cost effectiveness, regulatory requirements, and environmental impacts. Khan and Islam (2007) introduced a new approach in technology evaluation based on the novel sustainability criterion. In their study, they not only considered the environmental, economic, and regulatory criteria, but investigated sustainability of a technology. “Sustainability” or “sustainable technology” has been used in many publications, company brochures, research reports, and government documents which does not necessarily give a clear direction. Sometimes, these conventional approaches/definitions mislead to achieve true sustainability. Fig. 1.2 shows the directions of true sustainability in technology devolvement. It shows the direction of nature-based,

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FIGURE 1.2 Direction of sustainable and unsustainable technology (Khan and Islam, 2016).

inherently sustainable technology, as contrasted with an unsustainable technology. The path of sustainable technology is its long-term durability and environmentally wholesome impact, while unsustainable technology is marked by Dt approaching 0. Presently, the most commonly used theme in technology development is to select technologies that are good for t ¼ 0right now0, or Dt ¼ 0. In reality, such models are devoid of any real basis (termed “aphenomenal” by Khan and Islam, 2012, 2016), and should not be applied in technology development if we seek sustainability for economic, social, and environmental purposes. In addition to technological details of an appropriate drilling technology, the sustainability of this technology is evaluated based on the model proposed by Khan and Islam. Fig. 1.3 shows the detailed steps for its evaluation. The first step of this method is to evaluate a sustainable technology based on time criterion (Fig. 1.3). If the technology passes this stage, it would be evaluated based on criteria such as environmental, economic, and social variants. According to Khan and Islam’s method, any technology is considered sustainable if it fulfills the environmental, economic, and social conditions ðCn þ Ce þCs Þ  constant for any time, t, provided that dCnt =dt  0, dCet =dt  0, dCst =dt  0. To evaluate the environmental sustainability, a proposed drilling technique is compared with the conventional technology. The current drilling technologies are considered to be the most environmentally concerning activities in the whole petroleum operations. The current practices produce numerous gaseous, liquid, and solid wastes and pollutants, none of which have been completely remedied. Therefore, it is believed that conventional drilling has negative impacts on habitat, wildlife, fisheries, and biodiversity. For analyzing the environmental consequences of drilling, conventional drilling practices need to be analyzed, which will be continued, chapter by chapter, in this book on sustainability. In conventional drilling, different types of rigs are used. However, the drilling operations are similar. The main tasks of a drill rig are completed by the hosting, circulating, and rotary system, backed up by the pressure-control equipment. A drill bit is attached at the end

1.5 Toward achieving sustainability in drilling

FIGURE 1.3

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Flowchart of sustainability analysis of a drilling technology.

portion of a drill pipe. Motorized equipment rotates the drill pipe to make it cut into rocks. During drilling, many pumps and prime movers circulate drilling fluids from tanks through a standpipe into the drill pipe and drill collar to the bit. The muds flow out of the annulus above the blowout preventer over the shale shaker (a screen to remove formation cutting), and back into the mud tanks. Drilling muds are composed of numerous chemicals, some of which are toxic, and which are harmful to the environment and its flora and fauna. These issues will be discussed in the drilling mud chapter. The conventional practice in the oil industry is to use different drilling techniques, where huge capital is involved, and which create huge environmentally negative impacts. The technology is also more complicated to handle. Therefore, sustainable petroleum operation is one of the important keys for our future existence in this planet.

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1.5 Toward achieving sustainability in drilling The challenge to seeking sustainability is in taking a fundamentally new approach. It no longer suffices to resort to innovations, these innovations have to be sustainable. In recent years, a unique way has been devised that considers the extent to which oil and gas patents are being leveraged over time by nonpetroleum patents. Just as technologies combine in unique ways over time within the petroleum patent universe, technologies developed by petroleum companies are also cited outside of the petroleum universe. Higher synergies between disparate technologies move them into stronger and more central locations within the broader patent universe. Location in the knowledge network is important, because the more centrally located technologies have a greater chance of quickly incorporating innovations from neighboring technology areas. By way of contrast, technologies that are at the fringe of the knowledge network have fewer chances of bridging into totally new knowledge areas and creating genuinely disruptive innovations. Recent Deloitte (n.d.) report indicates, semiconductor devices, which were among the fastest growing patent area in the oil and gas industry at the time (growth and volume by technology), connect widely within the patent universe because of their cross-sectional applications across industries. In contrast, earth drilling, petroleum technology’s highest volume area of patenting, appears on the knowledge map with some connections but not as deeply connected to as many other technologies. Also, some of the technologies it links to are not centrally located in their own right (such as oilfield technology, which only connects to two other technologies). This makes it less likely that the oil and gas industry’s current stock of granted earth drilling patents will result in advances based on bridging technologies from genuinely different fields of science. In developing sustainable technologies, “peripheral” technologies play a pivotal role. The term Energy Innovation Index (EII) was introduced by Deloitte (n.d.) to express the drift in aggregate of innovation within the petroleum industry as a whole by producing a weighted average across all technologies. Technologies with high petroleum contributions and a commanding location in the patent network contribute positively toward the O&G aggregate score. When a core technology in the oil and gas industry drifts away from the center of the patent universe or has a decreasing contribution from the petroleum industry, it causes a decline in the EII. When EII is computed, it shows a slight decline over time. This means that the overall petroleum industry seems to be moving toward the edge of the overall patent universe. This should not be interpreted as a slowdown in the pace of innovation within oil and gas, but rather that other industries have likely accelerated their intensity and interconnectedness of innovation faster over the past decade or soda decade in which advances in IT and communications technologies have become pervasive. It also reflects the fact that many of the meaningful innovations in the oil and gas industry have come from combining existing petroleum technologies rather than “moon shot” innovations combining more distant technologies. In this context, the monitoring technology is worth a mention. New research findings have helped with accurately predicting pore pressure and fracture gradients, making it possible to advance such technologies as underbalanced, managed pressure and air drilling

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with low rheology drilling muds and cements. Now, if the mud and cement system had to be recalibrated based on sustainable development, one need to reconstruct the EII, because several aspects of the innovations would have contributions from other fields. One of the most important technologies developed in the new millennium is the so-called zipper fracturing. It is a completion methodology commonly executed in many shale developments. It was originally called “simulfrac,” and tested in Barnett shales of USA. Initially, operators implemented zipper fracs to enhance operational efficiency and to reduce cycle time between frac stages through drilling of parallel wells. The objective is to utilize fracture network in creating greater transmissivity. This technology has become popular ever since the first implementation in 2012 and has proven to enhance production as well as ultimate recovery. EII for this technology shows strong trends because this is the technology that has sustainable technologies embedded in it. By 2012, lesser-cited categories such as metalworking (patents comprising of new processes, tools, machines, and apparatuses made from metal) had emerged as a key linking technology, or a bridge, between earth drilling and other O&G-related technologies. Combined with its high growth rate of 192% from 2006 to 2015, metalworking has become a technology area that has not only grown in volume but seemingly also in its significance within the oil and gas knowledge network.

1.5.1 Challenges in waste management Drilling and production phases are the most waste-generating phases in petroleum operations. Drilling mud are condensed liquids that may be oil- or synthetic-based wastes, and contain a variety of chemical additives and heavy minerals that are circulated through the drilling pipe to perform a number of functions. These functions include cleaning and conditioning the hole, maintaining hydrostatic pressure in the well, lubrication of the drill bit and counterbalance formation pressure, removal of the drill cuttings, and stabilization the wall of the drilling hole. Water-based muds (WBMs) are a complex blend of water and bentonite. Oil-based muds (OBMs) are composed of mineral oils, barite, mineral oil, and chemical additives. Typically, a single well may lead to 1000e6000 m3 of cuttings and muds depending on the nature of cuttings, well depths, and rock types. A production platform generally consists of 12 wells, which may generate (62  5000 m3) 60,000 m3 of wastes. The current challenge of petroleum operation is how to minimize the petroleum wastes and its impact in the long-term. Conventional drilling and production methods generate an enormous amount of wastes (EPA, 2000). Existing management practices are mainly focused to achieve sectoral success and are not coordinated with other operations surrounding the development site. The following are the major wastes generated during drilling and production. a. b. c. d. e.

Drilling muds Produced water Produced sand Storage displacement water Bilge and ballast water

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1. Introduction

Deck drainage Well treatment fluids Naturally occurring radioactive materials Cooling water Desalination brine Other assorted wastes

The most significant advancement in sustainable petroleum operations has been in the areas of zero-waste engineering (Khan and Islam, 2016). This scheme emerged from petroleum policies from decades ago that required oil and gas companies to investigate no-flare technologies. Bjorndalen et al. (2005) developed a novel approach to avoid flaring during petroleum operations. Petroleum products contain materials in various phases. Solids in the form of fines, liquid hydrocarbon, carbon dioxide, and hydrogen sulfide are among the many substances found in the products. According to Bjorndalen et al. (2005), by separating these components through the following steps, no-flare oil production can be established Fig. 1.4. Simply by avoiding flaring, over 30% of pollution created by petroleum operation can be reduced. Once the components for no-flaring have been fulfilled, value-added end products can be developed. For example, the solids can be used for minerals, the brine can be purified, and the low-quality gas can be reinjected into the reservoir for EOR.

FIGURE 1.4

Breakdown of the no-flaring method (Bjorndalen et al., 2005).

1.6 Introduction to various chapters

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1.5.2 A novel desalination technique Management of produced water during petroleum operations offers a unique challenge. The concentration of this water is very high and cannot be disposed of outside. In order to bring down the concentration, expensive and energy-intensive techniques are being practiced. Recently, Khan and Islam (2016) have developed a novel desalination technique that can be characterized as a totally environment-friendly process. This process uses no nonorganic chemical (e.g., membrane, additives). This process relies on the following chemical reactions in four stages: (1) (2) (3) (4)

saline water þ CO2 þ NH3 precipitates (valuable chemicals) þ desalinated water plant growth in solar aquarium further desalination

This process is a significant improvement over an existing US patent. The improvements are in the following areas: - CO2 source is exhaust of a power plant (negative cost) - NH3 source is sewage water (negative cost þ the advantage of organic origin) - Addition of plant growth in solar aquarium (emulating the world’s first and the biggest solar aquarium in New Brunswick, Canada). This process works very well for general desalination involving sea water. However, for produced water from petroleum formations, it is common to encounter salt concentration much higher than sea water. For this, water plant growth (Stage 3 above) is not possible because the salt concentration is too high for plant growth. In addition, even Stage 1 does not function properly because chemical reactions slow down at high salt concentrations. This process can be enhanced by adding an additional stage. The new process should function as: (1) (2) (3) (4) (5)

Saline water þ ethyl alcohol saline water þ CO2 þ NH3 / precipitates (valuable chemicals) þ desalinated water / plant growth in solar aquarium / further desalination

Care must be taken, however, to avoid using nonorganic ethyl alcohol. Further value addition can be performed if the ethyl alcohol is extracted from fermented waste organic materials.

1.6 Introduction to various chapters 1.6.1 Chapter 2: State-of-the-art of drilling engineering Drilling is one of the oldest technologies known to mankind. This chapter reviews the history of drilling going back to the ancient period, when sustainability was assured due to the use of all natural products and technologies (Khan and Islam, 2016). The bifurcation point in time when unsustainable technologies were inserted to regular use is identified.

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1. Introduction

The technological development in the post industrial period is reviewed in light of sustainability as well as efficiency and ease of implementation. A sustainability analysis is performed for each component of drilling, such as drilling fluid, drilling hydraulics, casing design, cementing technology, drill string design, bit selection, materials, all the way to completion. The sustainability criteria developed by Khan and Islam (2007) are used. Discussion on emerging technologies and the direction of sustainability development is determined. The salient features of sustainable drilling are presented and their feasibility and impact discussed. The role of environmental impact and measures to achieve environmental sustainability are presented.

1.6.2 Chapter 3: Advances in directional drilling Before horizontal well technology took root, directional drilling was limited to offshore and certain reservoirs with special features. Today, it is understood that the directional drilling technology is useful for all drilling, including in horizontal well, vertical well, and others. It is because reservoirs are mostly heterogenous and it is impossible to maintain a drilling hole with predetermined geometry. In most cases, a driller has to deal with directional wells during the drilling period. In this chapter, the theories of directional drilling are presented along with their limitations. Advances made during the past 40 years in both monitoring and drilling accuracy are presented, along with the sustainability of these technologies. Emerging trends of drilling technologies are discussed. The effect of sustainability (or lack of it) is presented and remedial measures discussed. Future trends, when sustainability is assured, are discussed along with research areas that need to be focused. Guidelines for achieving total sustainability are presented. Several exercises, which include sustainability determination using Khan and Islam (2007) model, are presented. Finally, a set of problems ensure that the reader is able to address real problems, which are open-ended.

1.6.3 Chapter 4: Advances in horizontal well drilling Horizontal well technology is considered to be the most important innovation in drilling (Hossain and Islam, 2018). While horizontal wells have been widely implemented over the past four decades, the technology is far from being perfected, let alone sustainable. Currently used theories are presented in this chapter. An evaluation of these theories is performed vis-avis their ability to predict horizontal well drilling activities with accuracy compared. There are a number of horizontal drilling models that are commercially available. The merit and demerit of each of these models will be discussed. Emerging technologies and future research needs in terms of sustainable development will be presented.

1.6.4 Chapter 5: Advances in drilling technologies Advances in drilling technologies mark the most important developments in the discipline of petroleum engineering. Phenomenal strides have been made in both accuracy and speed of a drilling process. The most recent “revolution” in unconventional oil and gas production has been triggered by advancement in original well drilling as well as sophisticated managed drilling, including underbalance drilling, mudcap drilling, casing drilling, and others. Equally phenomenal progress has been made in offshore drilling, for which innovative technologies have been used.

1.6 Introduction to various chapters

15

Ever since horizontal drilling commenced in the 1980s, one landmark has been the length of the horizontal well drilled. In the beginning, a kilometer long well was considered to be a technological marvel. Today, neither length nor accuracy of the well placement is considered to be difficult task. Challenges still persist, along with predictability, but drilling deep ocean wells with many lateral offshoots is something drillers can undertake on a routine basis. The technological advancements in high pressure/temperature conditions will be discussed in this chapter. For each application, sustainability is analyzed. Technological advances following the current trends are compared with advances that could potentially take place if sustainability were the primary objective. This discussion makes it clear the opportunities and challenges imposed by sustainable developments.

1.6.5 Chapter 6: Drilling in unconventional terrains It is no exaggeration to state that the newfound American solvency in oil and gas is due to advances made in development of unconventional reservoirs. Horizontal well drilling along with fracturing techniques have made it possible to access formations that were not accessible before 2008, when the robust development of unconventional reservoirs began. Chapter 6 discusses challenging drilling environments in high pressure shale gas and presents solutions with a range of options. Casing design and new technologies, such as managed pressure drilling are discussed in detail. Special rig requirements are highlighted. Challenges encountered during the drilling of tight oil and gas formations are discussed. Challenges owing to harsh environmental conditions as well as high toxicity of the formation fluid are presented, along with sustainable solutions. Emerging technologies for both these two categories are presented, including those in environmentally sustainable mud selections. During the last few decades of the past century, the most significant technological advances in petroleum engineering have been in the topic of offshore drilling. The emerging technologies in offshore applications are discussed.

1.6.6 Chapter 7: Monitoring and global optimization Innovations from other disciplines have been merged into petroleum engineering applications. Such technologies are, monitoring and dynamic optimization, sonic while drilling, rotary steerable system offerings, and others. In the past, the focus was safety. However, the focus now has shifted toward environmental integrity and global ecosystem. In Chapter 7, all existing technologies will be evaluated for long-term sustainability. Global optimization, which includes mechanical, economical, and environmental sustainability in real time, is relatively a new concept. By determining global optimization, one can compare one set of technologies with another and make the final determination on the fate of a technology. This analysis is amenable to real-time data acquisition and adaptive control. Certain data can also be used to optimize a drilling process and dynamic reservoir characterization, whenever appropriate. The current state-of-the-art in real-time data acquisition, sonic while drilling, adaptive control, optimization of rate of penetration (ROP) will be presented in detail. The optimization of the fluid system and how fluid data can be utilized to characterize the drilled formation, as well as the formation ahead to the benefit of drilling, will be discussed.

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1. Introduction

1.6.7 Chapter 8: Environmental sustainability This chapter evaluates the environmental sustainability of drilling technologies. Conventional sustainability starts with technical sustainability prior to economical and environmental sustainability. In this book, the sequence is changed to environmental sustainability first. This change of sequence shows that if zero-waste engineering is used, environmental sustainability is necessary and a sufficient condition to overall sustainability. For all major drilling technologies, ranging from mechanical system, energy usage to fluid and hydraulic system, environmental sustainability is determined. Also included is a discussion of a number of novel technologies that restore environmental integrity of a drilling operation.

1.6.8 Chapter 9: Summary and conclusions This chapter summarizes each chapter, including the introduction. Key conclusions are highlighted and include long-term implications. At the end of the book is an appendix, which includes description of five recent patents and a comprehensive list of references and bibliography with hundreds of citations listed in over 50 pages.

C H A P T E R

2 State-of-the-art of drilling 2.1 Introduction It is well known that the petroleum industry drives the energy sector, which in turn drives the modern civilization. Although drilling of petroleum wells is the most known application of drilling technologies, drilling wells goes back in time to the origin of human civilization. Initially wells were drilled to make water available. Ground water being the best form of drinking water, humanity was dependent upon the extraction of groundwater, with wells being the primary form of water extraction. Later, long before the golden era of petroleum, wells were being drilled for extracting fossil fuel, which used to be used in its natural state. In the modern era, the most important progress in technology developments has been made in drilling technology. As such, drilling engineering has been the cornerstone of petroleum engineering and modern energy systems. In this chapter, drilling engineering is viewed in its historical perspective in order to offer the state-of-the-art to the readership.

2.1.1 History of modern drilling engineering In documented history, the Chinese are considered to be the first people who drilled wells in order to produce brine some 2000 years ago. It wasn’t, however, rotary drilling. It was rather with a cable tool percussion method that was in practice. A number of historical documents also reveal that a similar technique was used in ancient India, as well as Russia. For India, it was to dig out groundwater whereas for Russia it was to produce solutions of common salt. Remarkably, it was in India that some form of rotary drilling was in practice centuries before modern rotary drilling became ubiquitous in the petroleum industry. However, these drilling operations did not involve the use of external mud systems. Instead, drilling was performed with water, which would transport debris in the form of mud through natural pumping actions. Until recently, it was accepted that “Colonel” Edwin Drake’s legendary well was the first oil well drilled in modern history. Captain Edwin L. Drake, a career railroad conductor who devised a way to drill a practical oil well, is usually credited to have drilled the first-ever oil well in Titusville, Pennsylvania, in 1859. Curiously, initial “thirst” for oil was for seeking a

Drilling Engineering https://doi.org/10.1016/B978-0-12-820193-0.00002-2

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© 2021 Elsevier Inc. All rights reserved.

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2. State-of-the-art of drilling

replacement for natural oils (e.g., from whales) as a lubricating agent. Recall the need for such oil owing to a surge of mechanical devices in mid 1800s. Drake’s was the first successful use of a drilling rig on a commercial well drilled especially to produce oil in Pennsylvania. They drilled to 69 feet. Even if one discards the notion that petroleum was in use for thousands of years, there is credible evidence that the first well in modern age was drilled in Canada. Canadian, Charles Nelson Tripp, a foreman of a stove foundry, was the first in North America to have recovered commercial petroleum products. The drilling was completed in 1851 at Enniskillen Township, near Sarnia, in present-day Ontario, which was known as Canada West at that time. Soon after the “mysterious” “gum bed” was discovered, first oil company was incorporated in Canada through a parliamentary charter. Unlike Captain Drake’s project, this particular project was a refining endeavor in order to extract fuel from bitumen. Tripp became the president of this company on December 18, 1854. The charter empowered the company to explore for asphalt beds and oil and salt springs, and to manufacture oils, naphtha paints, burning fluids. Even though this company (International Mining and Manufacturing) was not a financial success, the petroleum products received a honorable mention for excellence at the Paris Universal Exhibition in 1855. Failure of the company can be attributed to several factors contributed to the downfall of the operation. Lack of roads in the area made the movement of machinery and equipment to the site extremely difficult. And after every heavy rain the area turned into a swamp and the gum beds made drainage extremely slow. This added to the difficulty of distributing finished products. It was at that time that need for processing petroleum products in order to make it more fluid surfaced. In 1855, James Miller Williams took over the business of refining petroleum in Lambton County from Charles Nelson Tripp. At that time, it was a small operation, with 150 gallon/day asphalt production. Williams set out during a drought in September 1858 to dig a drinking water well down-slope from it but struck free oil instead, thereby becoming the first person to produce a commercial oil well in North America, 1 year before Edwin Drake. Also of significance is the fact that he set up Canada’s first refinery of crude oil to produce kerosene, based on the laboratory work of Abraham Gesner. Interestingly, Gesner was a medical doctor by training (from London) but took special interest in geology. He is the one credited to have invented kerosene to take over the previous market, saturated with whale oilda wholly natural product. It was this Gesner who in 1850 created the Kerosene Gas Light Company and began installing lighting in the streets in Halifax and other cities. By 1854, he had expanded to the United States where he created the North American Kerosene Gas Light Company at Long Island, New York. Demand grew to where his company’s capacity to produce became a problem, but the discovery of petroleum, from which kerosene could be more easily produced, solved the supply problem. This was the first time in recorded history artificial processing technique was introduced in refining petroleum products. Gesner did not use the term “refined” but made fortune out of the sale of this artificial processing. In 1861, he published a book titled: A Practical Treatise on Coal, Petroleum and Other Distilled Oils, which became a standard reference in the field. As Gesner’s company was absorbed into the petroleum monopoly, Standard Oil, he returned to Halifax, where he was appointed

2.1 Introduction

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a professor of natural history at Dalhousie University. It is this university that was founded on pirated money while other pirates continued to be hanged by the Royal Navy at Point Pleasant Park’s Black Rock Beach as late as 1844.1 Only recently, it has come to light that perhaps the modern world’s first drilling of an oil well, to a depth of 21 m, took place on the Absheron peninsula of Azerbaijan in 1846 (Mir-Babayev, 2002). The percussion method with wooden rods was employed. This would be 13 years before Drake’s legendary well in USA. In both cases, oil was being sought to replace natural lubricants, for which whale oil was the only option in the past. In June 1860, J.C. Rathbone drilled a discovery well to 140 feet using a steam engine on the banks of the Great Kanawha River in the Charleston, W.Va., area. The well produced about 100 barrels of oil a day. In 1863, the diamond core drill was invented by Rodolphe Leschot, a French engineer. Leschot patented the device in the United States. Historically, the ability of oil to flow freely has fascinated developers and at the same time ability of gas to leak and go out of control has intimidated them. Such fascination and intimidation continues today. While nuclear electricity is considered to be benign natural gas is considered to be the source of global warming, all because it contains carbondthe very component nature needs for creating an organic product. Scientifically, however, the need for refining stems from the necessity of producing clean flame. Historically, Arabs were reportedly the first ones to use refined olive oil. They used exclusively natural chemicals in order to refine oil (Islam et al., 2010). For its part, natural gas seeps in Ontario County, New York, were first reported in 1669 by the French explorer, M. de La Salle, and a French missionary, M. de Galinee, who were shown the springs by local Native Americans. This is the debut of natural gas industry in North America. Subsequently, William Hart, a local gunsmith, drilled the first commercial natural gas well in the United States in 1821 in Fredonia, Chautauqua County. He drilled a 27-foot-deep well in an effort to get a larger flow of gas from a surface seepage of natural gas. This was the first well intentionally drilled to obtain natural gas. Hart built a simple gas meter and piped the natural gas to an innkeeper on the stagecoach route from Buffalo to Cleveland. Because there was no pipeline network in place, this gas was almost invariably used to light streets at night. However, in late 1800s, electric lamps were beginning to be used for lighting streets. This led to gas producers scrambling for alternate market. Shallow natural gas wells were soon drilled throughout the Chautauqua County shale belt. This natural gas was transported to businesses and street lights in Fredonia at the cost of US$0.50 a year for each light (Islam, 2014). In the mean time, in mid-1800s, Robert Bunsen invented the “Bunsen burner” that helped produce artificial flame by controlling air inflow in an open flame. This was significant because it helped producing intense heat and controlling the flame at the same time. By the late 1920s, declining production in New York’s shallow gas wells prompted gas companies to drill for deeper gas reservoirs in Allegany, Schuyler, and Steuben counties. 1

A cairn in front of its administration building actually describes the university’s origins two centuries ago from a fund created to launder the ill-gotten gains of an early 19th century war crime committed by the Royal Navy against a customs house in the U.S. state of Maine several months after Anglo-American hostilities of the War of 1812 had officially concluded.

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2. State-of-the-art of drilling

The first commercial gas production from the Oriskany sandstone was established in 1930 in Schuyler County. By the 1940s, deeper gas discoveries could no longer keep pace with the decline in shallow gas supplies. Rapid depletion and over drilling of deep gas pools prompted gas companies in western New York to sign long-term contracts to import gas from out of state. It took the construction of pipelines to bring natural gas to new markets. Although one of the first lengthy pipelines was built in 1891dit was 120 miles long and carried gas from fields in central Indiana to Chicagodthere were very few pipelines built until after World War II in the 1940s (Fig. 2.1).

FIGURE 2.1 Howard Hughes Sr.’s patented dual-cone roller bit remains relevant even today “Fishtail” drill bits became obsolete when Howard Hughes Sr. patented the dual-cone roller bit. By pulverizing hard rock, the new bit with two rotating cones brought faster and deeper rotary drillingdtransforming the petroleum industry worldwide.

2.1 Introduction

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The following developments are listed by National Drilling (n.d.). 1. The percussion or Cable-tool method: This method involves the use of a manila hemp rope used to suspend the wooden rods and the drilling tools in the earliest operations. The manila line and wooden rods were eventually replaced by multiple-strand steel rope often called wire line or wire rope. The cable pulls the string of tools up and down as brought about by a spring pole or a walking beam at the surface. The heavy bit has a blunt chisel end which cracks, chips, and smashes the rock by the repeated blows delivered in a measured or regular cadence. The first adequately documented spring-pole well in America was drilled by David and Joseph Ruffner beginning 1806 and completed on January 15, 1808, on the bank of the Kanawha River near Charleston, West Virginia. They reached a total depth of approximately 60 feet of which 40 feet was in bedrock. It was a salt well and it was tubed with wooden pipe to prevent weaker salt water from mixing with the brine of their main pay zone. Their feat spurred the salt industry and eventually led to spring-pole drilling for oil. 2. In 1821, the first well specifically intended to obtain natural gas was dug in Fredonia, New York, by William Hart. It was a 27 foot well, aimed at obtaining a larger flow of gas to the surface. It was a remarkable feat because most of the natural gas produced in that era was manufactured from coal, as opposed to transported from a well. During those days, natural gas was used directly to light street lights and others. It wasn’t until the end of the 19th century after the other use of natural gas, for generating electricity, that natural gas demand rose dramatically. 3. In 1825, a patent was issued to L. Disbrow for the first four-legged derrick. The structure consisted of legs made of square timber wood. The girts were mortised and inserted into the wooden legs with keys so the structure could be dismantled. 4. The “American first oil well” was drilled in 1929. This oil well was discovered accidentally while drilling for brine. The pressure of the gas and oil underneath the surface forced an enormous geyser into the air. This is noted to be America’s first oil well. 5. Although artesian wells were in existence in France for centuries, Grennelle well in France was drilled using the dry rotary auger method. It was 1771 feet deep and took 8 years to complete (1833e41). 6. In 1841, the first patent on drilling jar was issued to William Morris, who used a spring pole. 7. In 1845, the French drilled with water circulation. A 560 ft well was drilled in 23 days. 8. In 1849, the mechanical percussion drill was invented by J.J. Couch. Steam was admitted alternately to each end of a cylinder. The drill was launched like a lance at the rock on the forward stroke, caught, and then drawn back on the reverse stroke, and then launched again. It was the first drill that did not depend on gravity. It went to work on the Hoosac-Tunnel project, which bored a passage for trains through hills near North Adams, Mass. 9. In 1857, Bowles patented reverse-circulation drilling. Reverse-circulation drilling consists in injecting the drilling fluid at the surface through the annular space and to circulate the cuttings-laden fluid back up through the inside of the drillstring. This technology has made a comeback in recent years (du Chaffaut and Wittrisch, 2005).

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2. State-of-the-art of drilling

10. In 1859, The Drake well was drilled. It was the first commercial oil well in America. A cable tool drilling technique was employed, successfully drilling 69 feet. It was also the first successful use of a commercial rig to drill an oil well. 11. In 1860, Steam-powered oil derrick was introduced. In June, J.C. Rathbone drilled a discovery well to 140 feet using a steam engine on the banks of the Great Kanawha River in the Charleston, W. Va. area. The well produced about 100 barrels of oil a day. 12. In 1863, the diamond core drill was invented by Rodolphe Leschot, a French engineer. Leschot patented the device in the United States. 13. In 1866, Peter Sweeney of New York City was granted a patent (No. 51,902), which included a series of descriptions similar to technology used in modern rotary rigs. His design improved upon an 1844 British patent by Robert Beart. Sweeney’s patent utilized a roller bit with replaceable cutting wheels such “that by giving the head a rapid rotary motion the wheels cut into the ground or rock and a clean hole is produced.” This is, in essence, the introduction of rotary drilling. To be noted here, the rotary drilling technique had been in use in India since the medieval era, although it was limited to water wells. 14. In 1866, Edward A.L. Roberts was awarded a patent for a device for increasing the flow of oil by using an explosion deep in a well. It was later named as the Roberts Torpedo. That point on, the concept of fracturing to increase flow from wells caught on. 15. In 1871, Simon Ingersoll received a patent for a rock drill on a tripod mount. The drill was designed for mining and tunneling. It enabled the operator to drill at virtually any angle. This was the beginning of the concept of directional drilling and eventual horizontal well drilling technology. 16. In 1875, a long-running tunnel drilling project was completed. Charles Burleigh, John W. Brooks, and Stephen F. Gates patented a mechanical drill meant to be used on the Hoosac tunnel: the compressed air Burleigh drill. The tunnel spurred several innovations in drilling technology, including the earlier Couch/Fowle drill. 17. In 1876, John Vivian was given the first U.S. patent for a diamond drill. While other drills before its time bored holes through a succession of blows, this invention allowed the core to remain intact. This made it very valuable for prospectors. The first application was a massive 9ʺ hole of a length of 1000 ft. 18. In 1880, the Bucyrus Foundry and Manufacturing Company was founded in Bucyrus, Ohio. The company later became famous in the drilling industry as BucyruseErie, a maker of cable-tool rigs, but it was an early producer of steam shovels. A steam shovel is a large steam-powered excavating machine designed for lifting and moving material such as rock and soil. It is the earliest type of power shovel or excavator. 19. In 1882, Baker Brothers drilled the first well with rotary equipment; pumped water with windmill; Yankton, Dakota Territory. The Baker brothers also used their rotary method for oil well drilling in the Corsicana field of Navarro County, Texas. Their rig was powered by a mule. 20. In 1884, Henry C. Sergeant started the Sergeant Drill Company to manufacture an air-driven rock drill he had invented. This drilling system consisted of compressed air

2.1 Introduction

23

to move the drill’s piston onto the steel in a hammering motion. In modern time, this technology was revived with the use of exhaust gas for deeper wells (Roy, 1962). Recently, in view of environmental concerns, the use of air drilling has generated interest. 21. In 1889, the first patent for an electric drill was issued to Arthur James Arnot. The new device was designed for rock drilling, primarily in coal mines. 22. In 1893, Australian Francis Davis invented the calyx drill. A rotary core drill that uses hardened steel shot for cutting rock, which will drillholes from diamond-drill size up to 6 ft (1.8 m) or more in diameter. Drilling is slow and expensive, and holes cannot be drilled more than 35 degrees off the vertical, as the shot tends to collect on the lower side of the hole. It is also called shot drill. 23. In 1897, John G. Leyner invented a water-cooled drill that helped dampen dust raised in drilling. 24. In 1900, Drillers at Spindletop, including brothers Curt and Al Hamill and Peck Byrd, noticed that muddied-up freshwater could help stabilize a formation and prevent borehole collapse. They started circulating it. This was the first use of drilling mud. 25. In 1901, Captain Anthony F. Lucas at Spindletop began drilling with a steam-driven rotary rig and a double-pronged fishtail bit. Spindletop helped promote rotary drilling as a viable alternative. In 1907, Shell began using rotary drilling on a modest scale in Romania, and in the United States, rotary drilling gained a reputation for making hole fast in the Gulf of Mexico. Standard Oil of California was impressed by results in Texas and Louisiana, and in 1908, the company hired six drillers from the Gulf Coast and bought three complete rotary outfits to drill the hard formations of California. 26. In 1903, Edmund J. Longyear and John E. Hodge formed Longyear & Hodge, the manufacturing partnership that would eventually evolve into Boart Longyear. The company’s early drills were steam powered. 26. 1906 Portable gas engines. After the Otto engine invention, portable engines, such as “Simplex” oil engines, in sizes 2- manpower to 9 nominal horsepower, became popular. They were replacing steam engines for drilling and other applications. 27. 1909, Howard Hughes Sr. and Walter Sharp introduced the Sharp-Hughes Rock Bit, which was nicknamed the “rock eater.” It was suited for deep boring through medium and hard rock. 28. In 1912, Steel derrick was patented. Patent was issued to Lee C. Moore for a system that clamped and secured bracing to steel pipe legs to build a steel derrick. Prior to this, oil derricks were commonly wooden cable tool rigs. 29. In 1915, rotary table and Kelly were invented. The origins of the powered turntable in the middle of the drill floor went back to Spindletop. The primary function of the rotary table was to transmit torque to the drillstring via the kelly, a section of pipe with a square cross-section that slotted through a similar shape on the rotating table. During the first few years of this technology, rotary tables were driven by chain from a sprocket on the hoist, or drawworks. Later on, in 1918, Victor York and Walter G. Black of Standard Oil Company of California were granted a patent for driving the rotary table with a shaft. This innovation guaranteed the ongoing success of the rotary drilling method. By 1930, rotary rigs had replaced cable-tool rigs in most places, except for drilling very shallow wells.

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2. State-of-the-art of drilling

30. In 1915, core splitter, the original form of coring device was invented. Hugh Roberts, working as a geologist for Edmund Longyear, designed a new form of technology called a core splitter, which divided cores into 3e5 inch lengths for better analysis. Drilling firms used Roberts’s core splitter as standard equipment. 31. In 1916, steel cable was introduced. Ever since, progress has been made in making cables stronger, more flexible, and durable (Zhao et al., 2014). 32 In 1917, sub was introduced. As wells were being drilled deeper, it became increasingly difficult to maintain a smooth or straight hole. The first form of remedy came when Hughes and his engineers invented the idea of a reamer, a large-diameter sub placed some way above the bit, with cutters to keep the hole in gauge. This invention along with 72 other patents made Hughes one of the most prolific petroleum engineers in the world. 33. In 1918, Victor York and Walter G. Black of Standard Oil Company of California were granted a patent for driving the rotary table with a shaft. This innovation guaranteed the ongoing success of the rotary drilling method. 34. In 1919, A.P.I. standards were introduced. This would have profound impact on efficiency and innovation in drilling engineering. 35. In 1920s, Drilling mud additives were introduced. Water was the first drilling fluid, and its usage is documented throughout history, going back to the ancient Egyptian, Indian, and Chinese cultures. However mud as drilling fluid began to surface in name of patented technology in the 1800s. Naturally, any use of water during drilling would create mud with in situ formation clay, which is ubiquitous, but its deliberate use was the technology that was patented. The first major changes to drilling mud occurred in the 1920s with the addition of weighting materials (barite, iron oxides) and usage of mined bentonite clays. This also gave rise to the first commercial drilling mud companies such as NL Baroid. As deeper and more difficult-to-drill wells were being accessed, the need to engineer mud quality became more important. In the 1930s, major research projects were devoted to altering mud qualities to fit specific needs of challenging environments, such as overpressured formations, unstable heaving shales, and hydrocarbon traps along salt dome flanks. The technical need evolved into environmental regulatory needs after 1970s, when EPA was established and environmental regulars were being put in place. In the following years, the environmental regulations have become the driver of new line of additives. 36. In 1922, Arthur L. Hawkesworth of the Anaconda Copper Mining Company developed the first extensively used detachable rock drill bit. 37. In 1925, the first diesel powered rig system was introduced. 38. In 1929, the first true horizontal oil well was drilled near Texon, Texas. The horizontal drilling would catch on only after some 5 decades. Today, majority of North American wells are drilled horizontally. 39. In 1930, Cal Talc, A. J. Lynch and National Pigment Chemical merged to form Baroid Sales Company. The new company, founded to serve the growing market for products for hydraulic rotary drilling, is based in Los Angeles. This was the time, artificial chemicals started to be inserted into natural mud systems. Today, the central idea

2.1 Introduction

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Mud characteristic optimization involves adding synthetic chemicals to find the optimal point. Courtesy US Patent US7825072B2.

FIGURE 2.2

behind mud engineering is to introduce clay-free entirely synthetic chemicals (see for instance, Carbajal et al., 2009). The problem is reduced to finding optimum for maximizing solid transport while simultaneously maximizing drilling rate of penetration (Fig. 2.2). 40. In 1931, Harlen Marsh invented the viscosimeter, later named as Marsh funnel. Unlike any other device, it measures the time required for a specific volume of fluid (mud for petroleum applications) to pass through a standard funnel. As per Poiseuille law, the time is inversely proportional to the viscosity, which can be correlated with the solid carrying capacity of mud. This is related to the consistency of the mud. Marsh funnel marks one of the very useful and innovative devices invented for drilling applications. 41. In 1933, the tricone bit was invented as a patent was issued to Hughes Tool Company (Picture 2.1). 42. In 1937, Cantilever-type drilling mast was invented. After the introduction of the standard derrick in 1908 by Lee C. Moore, a major development from Lee C. Moore was his 1937 jackknife cantilever-type drilling mast, which could be erected as a single piece. 43. In 1949, Mobile Drilling produced its first portable continuous flight auger (CFA) drill, such as Models B-27, B-31. 44. In 1953, the wireline core retrieval system was invented. The patent was granted to US Industries Inc. (Yancey and Taylor, 1953). For the first time, an undisturbed core and/ or core barrel could be retrieved without withdrawing the drillstem. 45. In 1955, World’s deepest cable tool well was drilled. Previously, the cable tool well was abandoned in June 3, 1953, by the New York State Natural Gas Corporation at a depth of 11,145! A water zone at this depth filled the hole to 55000 and when it became impossible to bail down this water, it was deemed impractical to continue. This deep well was drilled to test the Oriskany sand and the unexplored formations occurring

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PICTURE 2.1 Tricone bit was invented in 1933. Photo from public domain.

below this producing formation. It was located in Town of Van Etten, Chemung County, New York, 18 miles south of Ithaca and 18 miles north of Elmira. The well was drilled in two stages. The first section was completed August 10, 1949, at a depth of 83710 without encountering natural gas in commercial quantities. The well was not plugged at this depth but shut down in order that the rig could be removed and used in other operations. On November 15, 1951, the second or drilling deeper operation commenced and continued until February 27, 1953, when the water zone was encountered at 11,145’. Several noncommercial gas shows were encountered in drilling deeper. 46. In 1957, introduction of Compax, PDC bits took place. This was the beginning of synthetic materials for improving the performance of drilling bits (Picture 2.2).

PICTURE 2.2

Improving performance with synthetic materials. Photo from public domain.

2.1 Introduction

27

General Electric Research Lab (GE) introduced a new synthetic material made of diamond grains sintered together with cobalt. This new material, Compax, was an “engineered” diamond with hardness of diamond yet didn’t have weak cleavage planes. To make a cutter, a thin layer of the synthetic diamond material was deposited onto a disk-shaped tungsten carbide substrate so that the assembly, called a “compact,” could be attached to the bit. Bits with this kind of cutter are generically called PDC bits. Ever since, this line of drill bits has become very common. 47. In 1958, the first downhole drilling motors or mud motors were introduced. They were manufactured by Dyna-Drill. The motor was based on the 1930 Moineau design for progressive cavity pumps. 48. 1978, Mud pulse telemetry was introduced. Teleco Oilfield Services Inc., together with the U.S. Department of Energy, introduced mud pulse telemetry. Ever since, this technology has become quite popular for transmitting measurement while drilling data to the surface. Data transmitted by pulses, together with trigonometry, can give operators a three-dimensional plot of the well being drilled. This technology makes it possible to characterize the formation dynamically. Pulse telemetry improved on the slower process of wireline logging. Teleco was later acquired by Baker Hughes. 49. In 1978, hydraulic fracturing for improving recovery from tight/unconventional formations (instead of previously known stimulation operation) was introduced. George P. Mitchell of Mitchell Energy & Development Corp. began experimenting with hydraulic fracturing in horizontal wells in the Barnett Shale near Fort Worth. It wasn’t until 2000s that the technology caught on, but the groundwork was done in 1970s and 1980s. 50. In 1980, sonic drilling as drilling technology was introduced. The first one in operation was that of Versa-Sonic drill. Versa-Drill International Inc. and Bowser-Morner built this rig that incorporated Ray Roussy’s new sonic drillhead. Roussy had worked to improve and perfect the technology over more than 20 years from original designs, which modified oscillators for drilling purposes. Sonic drills are now widely used for sampling. The Picture 2.3 shows some of the earliest units used. 51. In 2012, “Zipper fracking” was introduced. In this process, two horizontal wells are drilled side by side. If both wells are fractured throughout the length, the entire formation becomes amenable to great increase in production. Because the fractures are created in a zipper fashion, the name “zipper fracking” applies. This process has great potential in shale oil and gas formations, and other unconventional formations. In the Barnett Shale in Texas, the zipper-fracked wells doubled the volume of a typical well. Table 2.1 shows how zipper fracking and other forms of innovative fracking (e.g., stacked fracking) can increase oil and gas production multifold in unconventional formations. The stacked fracking technology is useful when there are formations, stacked like a pancake (such is the case in the Bakken and the Eagle Ford and Permian Basin in Texas). 52. During 2008e13, rapid advancements in drilling technology took place as deeper, longer wells were being drilled at a record time. For instance, for the Bakken shale of North Dakota, 16,000-foot wells were taking an average of 32 days to drill in 2008. By 2013, the average drill time for 21,000 foot wells was 18 days or less.

28

2. State-of-the-art of drilling

PICTURE 2.3 TABLE 2.1

Sonic drilling unit. Photo source: U.S. Army Corps of Engineers Sacramento District.

Production improvements with zipper fracking and stacked fracking.

Shale region

Production per drilling rig (June 2011)

Production per drilling rig (June 2014)

Percent change

Niobrara (Colorado)

95 barrels per day

361 barrels per day

280%

Marcellus (Pennsylvania)

2427 mcf per day*

6516 mcf per day*

168%

Eagle Ford (Texas)

198 barrels per day

476 barrels per day

140%

Bakken (North Dakota)

213 barrels per day

505 barrels per day

137%

From St. Paul Research, 2018, website: https://stpaulresearch.com/2014/06/27/2-new-drilling-techniques-that-will-shatter-us-oil-expectations/.

2.2 Drilling methods 2.2.1 Brief history of oil discovery Geology and time have created large deposits of crude oil in various parts of the earth. It is a natural fluid and is the second most abundant fluid on earth (second only to water). Throughout history, petroleum products played some role in our civilization, although the focus on burning oil to produce energy is new and only started after mid 1800s. Initially petroleum was promoted as a substitute to coal, as alarms were sounded that we would run out of coal. Prior to that “golden era” of petroleum, petroleum was used for medicinal purposes, to caulk boats and buildings, and to lubricate machinery. Ancient people were using oil mainly as medicine. It turns out that sustainable use of petroleum requires us to use oil for diverse applications, rather than uniform use after refining (Islam et al., 2018). Around 600 BC, wells were drilled in China for brine, gas, and water where water was poured into these wells to soften the rock and to help removing cuttings (Apaleke et al., 2012a,b). The first oil discovery in human life was in Babylon (Current Iraq) as oil pits in

2.2 Drilling methods

29

450 BC. Then, the second discovery was in Macedonia in 325 BC, and this oil was used by Alexander the Great. The third discovery of oil was in Kirkuk, Iraq. However, according to Apaleke et al. (2012a,b), the earliest known oil wells were drilled in China in 347. The Chinese were using bamboo as modern drillpipe to extract oil. They were able to drill at a depth of about 800 feet using bits attached with bamboo poles. The use of oil was limited to evaporating brine, producing salt, and for lighting and heating. The petroleum industry in Middle East was established by the eighth century. This was due to the use of tar at the street lights in Baghdad. However, some people believe that in the ninth century, oil fields were developed in Baku, Azerbaijan to produce naphtha. The Persian alchemist, Mohammad ibn Zakariya Razi, produced kerosene from petroleum using the distillation process in the ninth century. That processing technology was sustainable and not a single component produced from the processing caused damage to the ecosystem (Islam, 2019). Kerosene was used mainly as kerosene lamps and was a substitute for refined oil, which was also refined using sustainable technology (Islam et al., 2010). The distillation process of crude oil was also carried out by Muslim alchemists to produce flammable products for military purposes. By the 12th century, distillation process became available in Western Europe through Islamic Spain (Hossain and AlMajed, 2015). History says Baku was the place where shallow pits were dug to facilitate collecting oil. The hand-dug holes, which were up to 115 feet deep, were in use by 1594. In fact, these holes were essentially oil wells and produced about 28,000 barrels of oil so far. The first breakthrough in the oil industry’s drilling history was the year 1849, when Russian engineer F.N. Semyenov used a cable tool to drill an oil well on the Apsheron Peninsula. In the west, Canada was the first place of commercial oil production, when James Williams drilled the first oil well in North America in 1857. Later, in 1859, the first well in the USA was drilled near Titusville, Pennsylvania, under the supervision of “Colonel” Edwin L. Drake, and it was about 69 feet deep. Table 2.2 shows the oil discovery in the different places around the world as an example case. The first commercial oil well was situated in the southwestern Ontario town of Oil Springs. Williams acquired some property that was known to have oil gum beds. He dug through the gum beds in search of the source of the oily deposits, and discovered crude oil. This first oil well was simply a hole in the ground, with oil rising up close to the surface. With the use of hand pumps, the oil was extracted at a rate of 37 barrels of oil per day. Williams built and operated a local distillery from which he refined and sold kerosene. Ontario’s first oil boomd reflected in town names such as Petroliadparalleled a larger oil boom in northern Pennsylvania, where energy dynasties were beginning to emerge. Oil was not being used widely on a commercial basis before middle of the nineteenth century. Nowadays oil is the backbone of a nation’s economy and the heart of modern civilization.

2.2.2 An overview of drilling engineering A multitude of issues are needed to be resolved even before the consultants or engineers ever see the prospect of the project. Most importantly, these phases of works are being completed before any drilling operation. Here, the principal party is called the operator. This operator is normally the “Oil Company,” who is a well-known major company or an independent. The operator employs the drilling consultant to protect and negotiate the

30

2. State-of-the-art of drilling

TABLE 2.2

First discovery of oil in different places in the world for commercial production.

Serial No.

Name of the country

First discovery of oil

01

Oil pits near Babylon

450 BC

02

Macedonia

325 BC

03

Kirkuk (Iraq)

100

04

China (used bamboo for extract oil)

347

05

Azerbaijan (for medicine)

1264

06

Poland

1500

07

Russia

1597

08

Australia

1800

09

Romania

1857

10

Ontario, Canada

1858 (first commercial use)

11

Pennsylvania, USA

1859

12

Lake Maracaibo, Venezuela

1878

13

Sumatra, Indonesia

1885

14

Norway/Netherland

1885

15

Nigeria

1907

16

Iran

1908

17

Tampico, Mexico

1910

18

Bahrain

1932

19

Saudi Arabia

1933

20

Kuwait

1938

21

Qatar

1939

22

Brazil

1939

23

Algeria

1956

24

United Arab Emirates

1960

25

Oman

1967

26

United Kingdom

1969

27

Sudan

1979

operator’s interest. Meanwhile, the operator also engages geologists to locate the area where s/he feels to have a good prospect for hydrocarbon reserve. The geologists may recommend drilling a wildcat well (a small exploratory oil well drilled in land not known to be an oil field to get the geological information) into an untested field, or s/he may recommend a

2.2 Drilling methods

31

development well (a well drilled in a proved production field or area to extract natural gas or crude oil) to get the desired information about the formation. The operator’s next objective is to hire a landman to acquire drilling rights. The oil companies normally have a paid staff of geologists and landmen. The main responsibility of landman is to determine who is going to own the minerals rights in the area to be drilled. He also tries to acquire lease rights from the landowner through a document which is called an “oil and gas lease.” So, the landman is the representative of the operator who takes care of all of the negotiation parts with landowner so that the terms and conditions would be acceptable for the operator. After getting the lease and approval of license, the operator then hires the drilling contractor (a contractor who owns the drilling rig and employs the crew to drill the well). At this stage, operator hires the specialist consultants (normally service companies) to conduct other rig side jobs, such as casing, cementing, logging, perforating, fracturing, acidizing, lost tool recovery, drilling fluid preparations. The geologists and reservoir engineers are again engaged to analyze the drilling results and to determine which zones, if any, are worth producing. If there are one or more potential zones, the well would be completed for production. On the other hand, if there are no formation zones, the well would be plugged and abandoned in accordance with the regulations that protect the water zones drilled through. The operator cannot just pick up the rig and leave the hole open. Finally, the operator is responsible for producing and selling the hydrocarbons from its proven zones. Petroleum and mineral resources are usually owned by the government of the host country. Normally, the ministry of petroleum/oil and gas (different names in different countries) is empowered on behalf of the government to invite companies to apply for exploration and production licenses within the country. Exploration licenses may be awarded at any time based on company’s reputation and terms and conditions. Exploration licenses do not allow a company to drill any deeper than certain depth and are used primarily to enable a company to acquire seismic data from a given area. Production licenses allow licensees to drill for, develop, and produce hydrocarbons from whatever depth is necessary. Costs of field development are so huge that major oil companies normally form partnerships to share the expenses. Typically, oil companies operate in joint ventures to reduce their individual risk as well. One of the companies within the joint venture is designated and empowered to act as an operator that actually supervises the work. As long as the governments of most nations issue licenses to explore, develop, and produce its oil and gas resources, the company needs to obtain a production license even before drilling an exploration well. Prior to applying for a production license, however, they will conduct an “investigation” exercise, in which they will analyze any seismic data they have acquired, analyze the regional geology of the area, and finally take into account any available information on producing fields or well tests performed in the vicinity of the prospect they are considering. Based on the above, and a general look at the exploration and development costs, the pricing, and tax regimes, the company will decide whether it would be worth developing the field (if a discovery were made) or not. If the project is considered worth exploring further, the company will try to acquire a production license and continue with the “exploration” phase of the field. This will allow the company to drill wells in the area of interest. It will in fact commit the company to drill one or more wells in the area. The exploration phase of the field development may begin with the company shooting extra seismic lines in a closer grid pattern than it had done previously. This will provide more detailed information about

32

2. State-of-the-art of drilling

the prospect and will assist in the definition of an optimum drilling target. Despite improvements in seismic techniques the only way of confirming the presence of hydrocarbons is to drill an exploration well (the well that helps to determine the presence of hydrocarbons). Drilling is very expensive, and if hydrocarbons are not found, there is no return on the investment, although valuable geological information may be obtained. With only limited information available, a large risk is involved (on average, only one in eight North Sea exploration wells are successful). If the company decides to go ahead for hydrocarbon presence, an exploration well proposal is drawn up to drill in the most likely position on the reservoir. The length of the exploration phase will depend on the success. There may be a single well or many wells drilled on a prospect in the exploration phase. If a viable discovery is made on the prospect, then the company enters the “Appraisal” phase of the field. During this phase more seismic lines may be shot and more wells will be drilled to establish the extent of the reservoir. These appraisal wells (a well that is drilled to establish the extent (size) of reservoir) will yield further information, on which future plans will be based. The information provided by the appraisal wells will be combined with all of the previously collected data. Engineers will investigate the most cost-effective manner through which they can develop the field. If the prospect is deemed to be economically attractive, this development design will culminate in the production of a field development plan. This plan will be submitted for approval. If approval of the development is received, then the company will commence drilling development wells (a well that is drilled in a proved production field or area to extract natural gas or crude oil) and construction of production facilities according to the development plan. Once the field is “on-stream,” the companies’ commitment continues in the form of maintenance of both the wells and all of the production facilities. After many years of production, it may be found that the field is yielding more or possibly less hydrocarbons than initially anticipated at the development planning stage, and the company may undertake further appraisal and subsequent drilling in the field. Once the field is no longer producing economically, the company will be required to abandon the field in a sustainable (i.e., safe and environmentally acceptable) fashion.

2.2.3 Role of drilling during field development Drilling plays the most significant role in the development of oil and gas fields. There are some step-by-step works that are normally followed by the operators during the development phase of an oil field. Fig. 2.3 shows a complete loop for different phases of the development works related to drilling engineering. In addition, to understand the process well, the following steps are mentioned while drilling an oil/gas well continued: 1. Complete or obtain seismic, log, scouting information, or other data 2. Lease the land or obtain concession 3. Calculate reserves or estimate from best data available 4. If reserve estimates show payout, proceed with well 5. Obtain permits from various government authorities 6. Prepare drilling and completion program 7. Ask for bids on footage, day work, or combination from selected drilling contractors based on drilling program

33

2.2 Drilling methods

Geological and Geophysical Analysis

Seismic Survey Drill Exploration Well Drill Appraisal Well Mud Logging (Lithological and textural description of formation from drill cutting, hydrocarbon shows)

Coring (Lithological and textural description from massive sample. Samples used for lab analysis – porosity, permeability, capillary pressure etc.)

Well Logging (Electrical, Radioactive and Sonic tools provide quantitative assessment of fluid types and distribution)

Well Testing (Following the well allows large representative samples of the reservoir fluid to be recovered. Pressure response of reservoir allows extent, producibility and drive mechanisms of the reservoir to be evaluated.)

Evaluated Information Gathered Above

From exploration and appraisal well information, compile geological model

Compile Economic Model

Drill Development Wells

FIGURE 2.3 Role of drilling during field development.

8. If necessary, modify program to fit selected contractor equipment 9. Construct road, location/platforms, and other marine equipment necessary for access to site 10. Gather all personnel concerned for meeting prior to commencing drilling (prespud meeting) 11. If necessary, further modify program 12. Drill well for production

34

2. State-of-the-art of drilling

Once a decision is made to drill a well, then the drilling engineer’s role comes into play. In this long process, a drilling engineer plays a vital role during drilling operations, including planning, design, and supervision. The following are some of the important responsibilities that are accomplished by the drilling engineer: • • • • • •

Well planning before drilling Monitor drilling operations including mud fluid Managing rig side people (i.e., management job) After drilling, review drilling results and recommend future improvements Prepare report General duties

2.2.4 Types of drilling wells If the subsurface hydrocarbon formations are identified from primary seismic survey, a decision is made to either develop the field to get more information from exploration, or to declare the field as abandoned. If the field is decided as a potential area of hydrocarbon production, actual drilling of one or more wells is necessary to determine whether or not sufficient accumulations of hydrocarbon exist as commercial quantities. Based on these strategic decisions and primary outcomes, drilling wells can be categorized into four types, such as exploration well, appraisal well, development well, and abandonment well. An exploration drilling well is often called a “Wildcat” well. It is drilled during the initial phases of exploration. The drilling is completed with the hope of getting the information whether the reservoir rocks contain any oil or gas. The main objectives of this drilling well are to determine the presence of hydrocarbons, to provide a geological data (such as cores, logs) for evaluation, conduct flow test through the well to determine its production potential, and to obtain the fluid samples for laboratory analysis. Once hydrocarbons are discovered, more drilling is done to test if the field is commercially viable or not. So, appraisal wells are those wells that are used to establish the extent (size) of the reservoir. This well helps in gathering information such as whether there is a sufficient amount of oil and gas to justify investing money in infrastructure to recover oil/gas to scale. The development wells are sometime called production wells. This well is drilled in a proved production field/area to extract hydrocarbons (i.e., natural gas/crude oil). This drilling well is done to create a flow path from the reservoir to the surface, and then through the production facility. Finally, if no hydrocarbon is found, the well that was drilled to gather the information needs to be closed to prevent possible environmental disaster. The well that is sealed and closed is called an abandonment well. This well can be an exploration or appraisal well. 2.2.4.1 Sequences of drilling operations The sequences of drilling operations can be categorized into three major steps. The first step is to initiate and accelerate the drilling of a hole on the earth’s surface for hydrocarbon extraction, the second step is the casing operations, and the third step is the completion of well. However, the second and third steps are basically needed to support drilling

2.2 Drilling methods

35

operations in a sustainable manner. When drilling operations continue, the second step needs to be accomplished simultaneously with drilling. The third step comes once drilling operations reach their target level. In general, several casing steps are completed to avoid blowout or any other consequences during drilling operations. However, when a well is drilled in high pressure zones, weak and fractured formations, unconsolidated formations, or sloughing shales, the second step must be completed without any excuse to avoid substantial destruction at the rig-side. Different casing sizes are required for different depths. In general, five different casing sizes are used to complete a well. Fig. 2.4 shows the different casings, such as outmost casing (or conductor pipe), surface casing, intermediate casing, production casing, and liner. As shown

FIGURE 2.4

Typical casing program showing different casing sizes and their setting depths.

36

2. State-of-the-art of drilling

in Fig. 2.4, these pipes are run to different depths, and one or two of them may be omitted, depending on the drilling condition. However, they may also be used as liners, or in combination with liners. Based on the above casing concept, the sequences of the drilling operations are outlined, considering an onshore oil field. Once the location is finalized, depending on primary seismic survey, a large diameter hole (normally 36ʺ) is drilled using a truck mounted mobile rig. This hole is only drilled to a shallow depth. It varies from 400 to 5000 in length at onshore, and up to 10000 at offshore. However, the conventional depth is 1000 and normal range is 500  1500 . The hole must be lined with steel pipe or casing (usually called conductor pipe). This is the outmost casing string. The main purpose of this casing is to hold back the unconsolidated surface formations and prevent them from falling into the hole. The conductor pipe is cemented back to the surface, and it is either used to support subsequent casing and wellhead equipment, or the pipe is cut off at the surface after setting the surface casing. Once the conductor is in place, the drilling rig is brought on to the site and set up for the next stage. A 3000 casing shoe is used in this example (Fig. 2.4). A smaller diameter bit must be used to drill the next section below the conductor. If the conductor is 3000 diameter, a 2600 bit may be used. This 2600 hole may be drilled down to 20000 (normal range 3000  50000 ) through unconsolidated formations, which may cave in. The hole must be lined with another string of casing (surface casing) which may be up to 2000 diameter as an example (Fig. 1.2). The size of the surface casing normally varies from 700 to 1600 in diam00 00 eter and the most common sizes are 1034 and 1338 : The main functions of the surface casing string are to hold back unconsolidated shallow formations that can slough into the hole and cause problems, isolate freshwater formations, and to serve as a base on which to set the blowout preventers. The casing is lowered into the hole joint by joint, and then cemented in place. The intermediate or protective casing is set at a depth between the surface and production casings. The main reason for setting intermediate casing is to case off the formations that prevent the well from being drilled to the total depth. It is also used to counterbalance 00 the formation pressure. It varies in length from 50000 to 15; 0000 and 700 and 1134 in outside 00

diameter. In such case, a 1712 bit is used to drill the hole down to 60000 . In case some of the formations in this section prove troublesome (e.g., sloughing shales), another string of cas00 ing (1338 intermediate casing) must be run and cemented in place. 00 The next bit size is 1214 and drilling proceeds as before. By this time, we may be approaching the oil bearing formation zone. Any hydrocarbons can be detected by examining the rock cuttings, and if this proves favorable, we may want to evaluate the formation more fully. The drillstring is pulled out, and electric logs run on wire line are lowered into the hole. We may also want to take core samples, using a special bit which will allow recovery of a section of rock. A DST (drill-stem test) may be carried out to gain further data. Once all of the test data indicates the positive results, suspended pipes are run from the bottom of the next largest casing string, which is called a liner. Liners are the pipes that do not usually reach the surface. There are several types of liners, such as drilling liner, production liner, tie-back liner, scab liner, and scab tie-back liner. The major advantages of liners are that the reduced length and smaller diameter of the casing results in a more economical casing

37

2.2 Drilling methods

design than would otherwise be possible, and that they reduce the necessary suspending capacity of the drilling rig. However, possible leaks across the liner hanger, and the difficulty in obtaining a good primary cement job due to the narrow annulus, must be taken into consideration in a combination string with an intermediate casing and a liner. Before production casing or liner, if all the indications from the above tests are negative or show only slight indications of oil, the well will be abandoned. However, if positive results come, production casing is set through the prospective productive zones, except in the case of open-hole completions. It is usually designed to hold the maximal shut-in pressure of the producing formations. It is also designed to withstand stimulating pressures during completion and workover operations. Production casing provides protection for the environment in the event of failure of the tubing string during production operations, and allows for the pro00 00 duction tubing to be repaired and replaced. Production casing varies from 412 and 958 in diameter, and is cemented far enough above the producing formations to provide additional support for subsurface equipment and to prevent casing buckling. Production casing goes up to the formation zone. So, there is no specific length for this casing. It varies well to well, depending on the depth of formation zones. Finally, production tubing is place for hydrocarbon production (Fig. 2.4). The third or final stage of the drilling sequences is the completion phase.
As mentioned earlier, the completion of the well involves running the production casing 958

00

at total depth

(TD) to seal off  the oil producing zone (temporarily). Another string of pipe known as tubing
100 42 diameter is now run with a packer on the outside. When packer is positioned just above the pay zone (Fig. 2.4), its rubber seals are expanded to seal off the annulus between 00 tubing and 958 casing. A set of valves is initiated on the top of the casing to control the flow of oil once it reaches the surface. To initiate the production, a perforating gun is run down the tubing on wireline, and is positioned adjacent to the pay zone. Holes are shot through the casing and cement into the formation. The hydrocarbons flow into the wellbore and up the tubing to the surface. 2.2.4.2 Organization chart and manpower requirements during drilling operations Drilling requires many different skills and involves many different companies. The manpower needed to complete the drilling operations is normally engaged from three separate organizations. The organizations, such as drilling contractor, well operator, and drilling services companies, work together and provide manpower as required and requested. A typical drilling organization chart is shown in Fig. 2.5. The oil company seeking to exploit the petroleum reserves is known as the “Well Operator.” The operator bears overall responsibility for drilling operations. The company representative makes the rig-side spot decisions based on the well plan for drilling operations and other services if necessary. The planning of the well is usually done by the operator’s staff engineers working at headquarters/control office in town. They draw up a drilling program that must be followed as the well is being drilled. Usually the operator will have a representative on the rig (sometimes called the “company man”). His job is to ensure that drilling operations go ahead as planned, to make decisions affecting progress of the well, and to organize supplies of

38

2. State-of-the-art of drilling

FIGURE 2.5

Drilling rig organizational chart.

equipment. Any consumable items (drilling bit, drillpipe, cement, etc.) must be provided by the operator. He will be in daily contact with his drilling superintendent in the main control office in town. There may also be a drilling engineer and/or a geologist on the rig employed by the operator. The oil company usually employs a “Drilling Contractor” to actually drill the well. The contractor provides the rig and the crew to operate it. The drilling contractor is responsible for maintaining the rig and the associated equipment. The rig operation and rig personnel supervision are the responsibilities of drilling contractor. The drilling contractor will have a tool pusher in overall charge of the rig. He is responsible for all rig floor activities, and coordinates with the company man to ensure progress is satisfactory. Since drilling continues 24 hours a day, there are usually two drilling crews. Each crew works under the direction of

2.2 Drilling methods

39

the driller (or tool pusher). The crew will generally consist of a derrick man (who will also be liable for the pump while drilling continues), three roughnecks (working on the rig floor), plus a mechanic, an electrician, a crane operator, and roustabouts (general laborers). During the course of the well, certain specialized skills or equipment may be necessary (logging, surveying, etc.). The jobs are done by the appointed service companies. The service companies are employed by the operator. They provide all the specialized logistic supports and rig-side services. The service company’s personnel work on the rig as and when required. Sometimes they are employed on a long-term basis (e.g., mud engineer), or only for a few days (e.g., casing crews), based on demand at rig-side.

2.2.5 Various types of drilling In the previous section, we have seen how various drilling techniques evolved. Although, today some of these drilling practices are rarely active, they all offer viable options depending on the type of formations, geographic location, soil type, and other features. Most importantly, some of them may be more amenable to sustainability than others and the like. These techniques can be listed under the following categories (Funnell, 2016). 1. Percussion or Cable Drilling 2. Rotary Drilling 3. Dual-Wall Reverse-Circulation Drilling 4. Electro-Drilling 5. Directional Drilling 2.2.5.1 Percussion or cable drilling Percussion drilling is the manual drilling technique that was used in the first well drilled in North America. In this drilling technique, a hammering bit is attached to a long cable that is then lowered into a wide open hole. As such, it is also called cable drilling, wherein the driller uses a tripod to support the tools. By going back and forth with the bit, the action loosens the soil in the borehole, which is then extracted with the help of a bailer. At intervals, the bit is removed while the cuttings are suspended in water, which is then removed by pumping to the surface. The percussion or churn drill digs a vertical hole. It employs the principle of freely falling chisel bit hung on a cable to which percussive motion is imparted by one of the various types of power units. The power units are manual lift and drop, compressed air, and electrically driven winches. The tungsten carbide bit fitted in a hammer is lifted few meters and allowed to drop (Fig. 2.6) to hit the bottom of the hole. The process continues in succession. The churning motion of the bit crushes and scraps the ground, and so a hole is dug. The cutting of rocks thus produces mud or slurry by lowering water. The crushed material is removed from the bottom of the hole at a regular interval to make a sample. Churn drilling is suitable for soft and medium formation. In harder formation resharpening of cutting bit is required frequently resulting in lowering of progress. The capacity of the churn drill in its original form is limited to relatively short holes, under 40 m. Unless the formation is consolidated, a steel casing is necessary to prevent the collapse of the hole. Similarly, the casing may have to be cemented/isolated in order to

40

2. State-of-the-art of drilling

FIGURE 2.6

Schematic conceptual diagram of the percussion drilling procedure. From Halder, 2013.

protect the hole from contamination or prevent the hole from being a vehicle to bring various layers in communication (triggering environmental concerns). Only an uncemented casing can be used temporarily after permanent screen or casing is installed. The percussion drilling itself is classified as top-hammer drilling (THD), down-the-hole (DTH) drilling, and rotary drilling (RD) rigs, depending on the operating method used (Song et al., 2016). Fig. 2.7 shows various methods. In general, THD is used mostly for mining and civil blasting works, for which the drilled hole is restricted to a length of 40 m at the most. DTH is used mainly for groundwater development and can create holes to a maximum depth of 4000 m. Although this depth is greater than many oil and gas wells, DTH is not applied to petroleum wells. Rotary drilling (RD) is most commonly used for petroleum production and geothermal development. In this technique, the drill bit is propelled by its own weight to reach depths of up to 10,000 m formations resulting in low progress at high labor cost. The capacity of the churn drill is limited to relatively short holes of 10e50 m. The principal mechanism involved in percussive drilling mechanism is the generation of percussive energy with repeated impact of the drifter (THD rigs) or the DTH hammer (DTH rigs). This energy is coupled with the feed force and rotation force that are transmitted to the drill bit through the drill rod. The energy generated from the repeated impacts is then converted into wave energy, which is transmitted to the rock via the drill bit. Finally, the drill bit, now with enough impact energy for drilling, cuts into and crushes the rock. The rate at which the impact-generated energy in a percussive drilling system is transmitted is determined by complex effects such as drilling rod, coupling sleeve, the compressive strength of the rock, and interactions between the drill bit and the rock. The process

2.2 Drilling methods

41

FIGURE 2.7 Drilling mechanisms of two types (A and B) of percussive drilling system as compared to rotary drilling (C).

has been studied for a simplified system. For instance, Li et al. (2000) used stress wave theory along with energy conservation law to analyze both DHT and DTH impacts and then related them to impact resistance index and rock hardness. With that analysis, it is found that certain drilling methods are highly efficient, with high rates of penetration, when drilling soft rock (uniaxial compressive strength, UCS, < 20 MPa) or medium hard rock (UCS 50e120 MPa), but the efficiency decreases when drilling very hard rock (UCS > 200 MPa).

42

2. State-of-the-art of drilling

There are numerous previous studies regarding drill bit, rock drilling, the transmission of impact energy, and drilling efficiency. Hustrulid and Fairhurst (1971a,b; 1972a,b) investigated energy transmission between the drill steel and rock and measured the specific energy resulting from the impact force. All design works follow modeling of a simplified model of the actual drilling process. The primary mechanism is the creation of crack within the rock body. The crack is initiated by the tensile stress associated with the expansion of the crushed zone during the loading process. In the crushed zone, the mechanism of side crack is mixed tensile and shear failure, but outside the crushed zone, the dominant mechanism of side crack is tensile failure. A comprehensive model is absent for this analysis but numerous semiempirical and semitheoretical relationships among the side crack length, the drilled rock property, and the drilling force are formulated to approximately predict the side crack length. In the simultaneous loading, the interaction and coalescence of side cracks induced by the neighboring button-bits with an optimum line spacing enable formation of largest rock chips, control of the direction of subsurface cracks, and a minimum total specific energy consumption. Based on this depiction, a formula was derived by Liu et al. (2008) to determine the optimum line spacing on the basis of the drilled rock properties, the diameter and shape of the button-bit, and the drilling conditions. In the rock fragmentation by multiple button-bits, most of the rock between the neighboring button-bits is chipped as a result of the coalescence of side cracks. In the remaining rock, the intensely crushed zones and significant extensional cracks are observed adjacent to the sidewall and the inside of the borehole. Fragment side distribution shows more than 80% of the fragments are fines in the crushed zones as well as the cracked zones, large fragments are indeed observed, which are the big chips caused by the coalescence of side cracks. Although not commonly well known, percussive drilling opens up opportunities for sustainable drilling practices. Consider some of US patents issued on the topic. Mishkin et al. (1973) invented a percussive drilling machine in which an air-operated striking rearhead connected to a hammer piston was used. The hammer piston reciprocates under the action of compressed air so as to deliver blows at a drill steel located at the front end of the machine. At the same time, a reversible rotary impulse fronthead has a body accommodating two rotatable and axially movable annular pistons provided with impact projections and indentations formed between the projections. While the original patent had an embedded highfrequency reciprocatory angular oscillations system, today, we have the technology for remote sensing that can make this process dynamic. Depending on the nature of the rock and in anticipation of the rock that lies ahead, a system can be optimized. Similarly, the rotary impulse fronthead that has a ratchet mechanism, which ensures the rotation of one of the annular pistons and the drill steel only in one direction, can be optimized dynamically depending on the drilled rock information. One significant advancement of this technology was in its application in directional drilling (Johns et al., 1993). In this invention, an air-operated hammer drill is used to onset and follow-up directional drilling. Similar to the 1973 invention, this one has a piston that reciprocates while simultaneously rotating within its housing. A hammer drill bit slidably keyed to the bottom of the piston transfers the impact energy to the formation and rotates during operation independent of an attached drillstring, making it ideally suited to directional drilling activities. Because the hammer impacts while simultaneously rotating the bit, maximum penetration of the bit is assured. Although in percussive drilling system, drill

43

2.2 Drilling methods

bit rotational parameters, e.g., torque and rpm, are not relevant from a rock formation breaking point of view, they become relevant in a directional drilling case. Typically, industry experience has proven that the bit optimum rotational speed is approximately 20 rpm for an impact frequency of 1600 bpm (beats per minute). This rotational speed translates to an angular displacement of approximately 4e5 degrees per impact of the bit against the rock formation. Another way to express this rotation is the cutters positioned on the outer row of the hammer bit move at the approximate rate of one half the cutter diameter per stroke of the hammer. Other patents in percussive drilling involve various forms of incremental improvement of the original concept. For instance, Guimaraes and Cruz (2009) invented a drill bit that has a central longitudinal axis and is operable by applying repetitive axial percussive impacts on the drill bit in a direction having a component along the axis and by applying rotary motion about the axis relative to the earth formation. The principal mechanism involves introducing one or more axial cutters for predominantly axially cutting the formation triggered by the axial percussive impacts and one or more shear cutters for predominantly shear cutting the subterranean earth formation in response to the rotary motion. Table 2.3 shows a list

TABLE 2.3

Patents in percussive drilling patent citations (43).

Publication number

Priority date

Publication date

Assignee

Title

US2998085A

1960-06-14

1961-08-29

Richard O Dulaney

Rotary hammer drill bit

US3140748A

1963-05-16

1964-07-14

Kennametal Inc

Earth boring drill bit

US3258077A

1963-12-30

1966-06-28

Phipps Orville

Piercing point hammer drill bit

US3269470A

1965-11-15

1966-08-30

Hughes Tool Co

Rotary-percussion drill bit with antiwedging gage structure

US3388756A

1965-03-29

1968-06-18

Varel Mfg Company

Percussion bit

US3709308A

1970-12-02

1973-01-09

Christensen Diamond Prod Co

Diamond drill bits

US3788409A

1972-05-08

1974-01-29

Baker Oil Tools Inc.

Percussion bits

US3955635A

1975-02-03

1976-05-11

Skidmore Sam C

Percussion drill bit

US4051912A

1976-02-03

1977-10-04

Western Rock Bit Company Limited

Percussion drill bit

US4296825A

1977-11-25

1981-10-27

Sandvik Aktiebolag

Rock drill

US4558753A

1983-02-22

1985-12-17

Nl Industries, Inc.

Drag bit and cutters

US4607712A

1983-12-19

1986-08-26

Santrade Limited

Rock drill bit

US4676324A

1982-11-22

1987-06-30

Nl Industries, Inc.

Drill bit and cutter therefor

US4716976A

1986-10-28

1988-01-05

Kennametal Inc.

Rotary percussion drill bit

US4823892A

1984-07-19

1989-04-25

Nl Petroleum Products Limited

Rotary drill bits (Continued)

44 TABLE 2.3

2. State-of-the-art of drilling

Patents in percussive drilling patent citations (43).dcont’d

Publication number

Priority date

Publication date

Assignee

Title

US4991670A

1984-07-19

1991-02-12

Reed Tool Company, Ltd.

Rotary drill bit for use in drilling holes in subsurface earth formations

US5004056A

1988-05-23

1991-04-02

Goikhman Yakov A

Percussion-rotary drilling tool

US5025875A

1990-05-07

1991-06-25

Ingersoll-Rand Company

Rock bit for a down-the-hole drill

DE4200580A1

1991-09-13

1993-03-18

Hausherr & Soehne Rudolf

Rock bit

US5244039A

1991-10-31

1993-09-14

Camco Drilling Group Ltd.

Rotary drill bits

EP0563561A1

1992-04-02

1993-10-06

Boart HWF GmbH & Co. KG Hartmetallwerkzeugfabrik

Superimposing drilling bit

US5460233A

1993-03-30

1995-10-24

Baker Hughes Incorporated

Diamond cutting structure for drilling hard subterranean formations

US5595252A

1994-07-28

1997-01-21

Flowdril Corporation

Fixed-cutter drill bit assembly and method

US5601477A

1994-03-16

1997-02-11

U.S. Synthetic Corporation

Polycrystalline abrasive compact with honed edge

US5890551A

1996-03-14

1999-04-06

Sandvik Ab

Rock drilling tool including a drill bit having a recess in a front surface thereof

US5992547A

1995-10-10

1999-11-30

Camco International (UK) Limited

Rotary drill bits

US6202770B1

1996-02-15

2001-03-20

Baker Hughes Incorporated

Superabrasive cutting element with enhanced durability and increased wear life and apparatus so equipped

WO2001033031A1 1999-11-03

2001-05-10

Relton Corporation

Multiple cutter rotary hammer bit

US6253864B1

1998-08-10

2001-07-03

David R. Hall

Percussive shearing drill bit

US6290002B1

1999-02-03

2001-09-18

Halliburton Energy Services, Inc.

Pneumatic hammer drilling assembly for use in directional drilling

US20020066601A1 2000-12-06

2002-06-06

Meiners Matthew J.

Rotary drill bits exhibiting sequences of substantially continuously variable cutter backrake angles

WO2002099242A1 2001-06-05

2002-12-12

Andergauge Limited

Drilling apparatus

45

2.2 Drilling methods

TABLE 2.3 Publication number

Patents in percussive drilling patent citations (43).dcont’d Publication date

Assignee

Title

WO2003004249A1 2001-07-03

2003-01-16

Boston Scientific Limited

Medical device with extruded member having helical orientation

US6527065B1

2000-08-30

2003-03-04

Baker Hughes Incorporated

Superabrasive cutting elements for rotary drag bits configured for scooping a formation

WO2003031763A1 2001-10-03

2003-04-17

Shell Internationale Research Maatschappij B.V.

System for rotary-percussion drilling in an earth formation

WO2003042492A1 2001-11-13

2003-05-22

Sds Digger Tools Pty Ltd

An improved transmission sleeve

US6672406B2

1997-09-08

2004-01-06

Baker Hughes Incorporated

Multi-aggressiveness cutting face on PDC cutters and method of drilling subterranean formations

WO2004104363A1 2003-05-26

2004-12-02

Shell Internationale Research Maatschappij B.V.

Drill bit, system, and method for drilling a borehole in an earth formation

WO2004104362A1 2003-05-26

2004-12-02

Shell Internationale Research Maatschappij B.V.

Percussive drill bit, drilling system comprising such a drill bit and method of drilling a bore hole

WO2004111381A1 2003-06-12

2004-12-23

Shell Internationale Research Maatschappij B.V.

Percussive drill bit

US6918455B2

1997-06-30

2005-07-19

Smith International

Drill bit with large inserts

US20050269139A1 2004-04-30

2005-12-08

Smith International, Inc.

Shaped cutter surface

US7104344B2

2006-09-12

Shell Oil Company

Percussion drilling head

Priority date

2001-09-20

of patents with their relevant information. The main principle of all these patents is the improvement of the transfer of energy from percussive to shear form. Fig. 2.8 shows the general trend of percussive force on the displacement of the bit. The chaotic nature of the graphs is indicative of the fact that the relationship is not linear and there are numerous other factors that play a role. 2.2.5.2 Rotary drilling Rotary drilling is the most common methods of drilling, especially for exploratory and production wells. The depth reached by rotary drilling can be as much as five miles below the ground. In 2008, an oil well was drilled to 40,318 ft in Qatar. In September 2009, the rig drilled the deepest oil well in history at a vertical depth of 35,050 ft (10,683 m) and measured depth of 35,055 ft (10,685 m) in the Tiber Oil Field at Keathley Canyon

46

2. State-of-the-art of drilling

FIGURE 2.8 The impact of force on bit displacement under different rock conditions. From Liu, H.Y., Kou, S.Q., Lindqvist, P.A., January 2008. Numerical studies on bit-rock fragmentation mechanisms. International Journal of Geomechanics 8 (1).

block 102, approximately 250 miles (400 km) southeast of Houston, in 4132 feet (1259 m) of water. More recently in 2016, a Maersk drillship has broken the world record for the deepest water depth for an offshore oil rig after spudding a well located more than two miles below the surface of the ocean. The well, known as the Raya-1 prospect, is being drilled offshore Uruguay in a water depth of 3400 m (11,156 ft). The rotary drilling includes a rotary table, which is connected to a square kelly, which then is connected to the drilling pipe. The mud swivel on the pipe is subsequently connected to blowout preventers. The pipe is known to rotate at a velocity of 40e250 rpm with the drill made of drag bits, sharp cutting edges, or rolling cutters with strong teeth. Cuttings are then removed by fluid circulation that gets inside the pipe. The penetration rate is faster when using air-based drilling fluids compared to the water-based ones. A drag bit is useful in this scenario to penetrate unconsolidated sediments, while the roller bit can drill through consolidated rock. The overall rotation speed of the drill can be increased or decreased depending on the hardness of formation material. A patent was issued in 1983 (Boyadjeiff, 1983) on a so-called top drive drilling system, which was an alternative to the rotary table and kelly system. A motor, which turns the drillstring, is connected to the upper end of the string and moves downwardly with the string during the drilling operation. This device permits a substantial reduction in the overall cost of drilling as compared with the standard rotary system having a rotary table and kelly. The original design was a well drilling apparatus including a powered drilling unit connectable to the upper end of a drillstring and adapted to rotate to drill a well. It came with a vertical extension guide track structure which guides the drilling unit for movement along the axis of the well. The original patent contained the following design and its extensions. 1. Well drilling apparatus comprising: - a mast or derrick; - a drilling unit including an element adapted to be connected to the end of a drillstring for rotation therewith about the axis of the string, and a motor operable to drive said element and the connected string rotatively about the axis;

2.2 Drilling methods

47

- a pair of elongated first guide rails; - a pair of shorter second guide rails forming lower extensions of the first rails; - a carriage by which the drilling unit is carried and engaging the rails for movement there along between an upper position of guided engagement with the first rails and a lower position of guided engagement with the second rails; and - a connection mounting at least one of the second rails to a corresponding one of the first rails for movement therewith between the drilling axis and inclined positions, and for swinging movement relative to the carriage and drilling unit to move the drilling unit from an active position of alignment with the axis to a retracted position at a side of the axis. 2. Possibly having a means for swinging first and second rails together relative to the mast or derrick between a given drilling position and inclined positions. 3. A latching mechanism for releasably retaining first and second rails in certain drilling positions. 4. Possibility of including a pair of third rails carried by the derrick above the first and second rails and in alignment therewith when the first and second rails are in their drilling positions, and which remain stationary while the first and second rails swing to given inclined positions thereof. 5. Possibility of other extensions for better control and connectivity of the third rail. This top drive drilling system enjoyed significant popularity during the 1980s mainly because it permits a substantial reduction in the overall cost of drilling as compared with the standard rotary system having a rotary table and kelly. However, for drilling in some areas the rotary table arrangement has had one advantage in that it requires the drillstring to be pulled upwardly off of the bottom of the hole each time an added length of pipe is connected to the upper end of the string. This may reduce the possibility of the string becoming stuck in the hole, as may occur when a string remains on the bottom without rotation while adding pipe to its upper end. Also, when drilling an offshore well from a floating vessel, elevation of the string off of the bottom of the hole while adding pipe to the string prevents damage to the string or other equipment or the well by intermittent movement of the lower end of the string into and out of engagement with the bottom of the well as the vessel moves upwardly and downwardly with wave motion. These shortcomings were addressed by another patent by Boyadjieff (1986). The new apparatus allowed a string driven by a top drive unit to be raised off of the bottom of the hole each time a length of pipe is added to the upper end of the string. In this invention, the string is raised to a position at which its upper threaded end to which the added length is to be connected is spaced substantially above the level of the rig floor, and is at a level at which it is not readily accessible to a person standing on the floor. A tong or other back-up tool engages the top of the string at that higher level and restrains it against rotation as the added length of pipe is connected threadedly to the upper end of the string. In one form of this invention, a platform is provided at an elevated location spaced above the level of the rig floor, and is adapted to support a person at that location to assist in making up a threaded connection between the raised upper end of the drillstring and the

48

2. State-of-the-art of drilling

lower end of the length of pipe being added thereto. The person may then manually move a back-up tong from a storage location at a side of the well to a position of engagement with the raised upper end of the drillstring. Preferably, the platform is itself mounted for movement between an active position of reception adjacent the upper end of the drillstring and a retracted inactive position in which it does not interfere with movement of the string and top drive unit during the drilling process. This movement of the platform may be relative to a walkway located near the platform and onto which a person may walk when the platform is in its retracted condition. In a second form of the invention, the back-up tool is mounted for movement between an active position in which it engages and restrains rotation of the upper end of the drillstring at the specified elevated location and a retracted position in which it is offset to a side of the string to avoid interference with the string and top drive unit during the actual drilling operation. The backup tool is preferably mounted to the end of an arm which swings between an upwardly projecting condition in the retracted position of the tool and a horizontally projecting condition in the active position of the tool. 2.2.5.2.1 Drilling parameters

The drilling parameters may be broadly classified under two types: - Rig and Bit Related Parameters; and - Formation Parameters. The rig and bit related parameters can be controlled but the formation parameters have to be dealt with. The following parameters control a drilling activity. 1. WOB 2. RPM 3. Pump parameters 4. Depth 5. Inclination 6. Azimuth 7. ROP 8. Drillstring properties 9. Casing details 10. Drilling fluid properties 11. Torque 12. Hook-load 13. LWD 14. MWD A brief description of these parameters follows. WOB: It is the abbreviation for “Weight on Bit.” It represents amount of weight applied onto the bit, which is then transferred to the formation which in turn is the energy created together with string speed that advances the drillstring. This parameter is measured

2.2 Drilling methods

49

through the drilling line, usually with a strain-gauge, which measures the magnitude of the tension in the line itself, and gives the indirect weight reading based on the calibration. This sensor measures a unique value, which is the overall weight (hook-load) of the string including the weight of the block and Top Drive System (TDS). TDS is a mechanical device on a drilling rig that provides clockwise torque to the drillstring to drill a borehole. It is an alternative to the rotary table and kelly drive. It is located at the swivel’s place below the traveling block and moves vertically up and down the derrick. RPM: This parameter stands for “rotations per minute.” It represents the rotational speed of the drillstring. With the invention of TDS, the reading is directly linked to the electronics of the unit itself. It is considered that the measurements for this parameter are accurate as long as the acquisition system setup has been thoroughly made up. Pump parameters: The pump parameters are composed of the liner size in use, pump strokes, and the pump pressure. In case there are two pumps working simultaneously, all of the data for two of the pumps should be acquired. With the electric pumps the stroke is transmitted in the same way as RPM. The pressure at the pump in case of having been acquired could be compared with the reliability of the standpipe pressure. Pump pressure should always be greater than the standpipe pressure. Use of flow meters could also be adapted for accurate flow rate measurements. Depth: The value of depth. This is indicated by the bit position. The depth is linked to the position of the block, and measured by means of the sensors located at the crown block. Depth is a primary parameter in the drilling process and is in the core of innovations in sensor technologies that have made MWD successful. InclinationdAzimuth: These two parameters are in the responsibility of the directional driller. However, this is also an important consideration for vertical wells, which invariably show some deviation throughout the drilling process. ROP: Rate of Penetration (ROP) is the most important parameter, since modern optimization techniques essentially maximize this rate and compare costs associated with different rates. It is measured through the relative change of the position of the block in time. Accurate calibrations are very important in order to have a representative ROP parameter. Factors known to have an effect on rate of penetration are listed under two general classifications such as controllable and environmental. Controllable factors are the factors which can be instantly changed such as weight on bit, bit rotary speed, hydraulics. Environmental factors on the other hand are not controllable such as formation properties, drilling fluid requirements. The reason that drilling fluid is considered to be an environmental factor is due to the fact that a certain amount of density is required in order to obtain certain objectives such as having enough overpressure to avoid flow of formation fluids. Another important factor is the effect of the overall hydraulics to the whole drilling operation which is under the effect of many factors such as lithology, type of the bit, downhole pressure and temperature conditions, drilling parameters, and mainly the rheological properties of the drilling fluid. Rate of penetration performance depends and is a function of the controllable and environmental factors. It has been observed that the drilling rate of

50

2. State-of-the-art of drilling

12 penetrations generally increases with decreased Equivalent Circulating Density (ECD). Another important term controlling the rate of penetration is the cuttings transport. Ozbayoglu et al. (2004) conducted extensive sensitivity analysis on cuttings transport for the effects of major drilling parameters, while drilling for horizontal and highly inclined wells. It was concluded that average annular fluid velocity is the dominating parameter on cuttings transport, the higher the flow rate the less the cuttings bed development. Drilling penetration rate and wellbore inclinations beyond 70 did not have any effect on the thickness of the cuttings bed development. Drilling fluid density did have moderate effect on cuttings bed development with a reduction in bed removal with increased viscosities. String-casing properties: The string and casing properties are very important when the frictional pressure losses are to be calculated. In addition to these hydraulic considerations, string-casing properties are also important from strength of materials perspective. Fluid properties: Rheological properties and the density of the drilling fluids are also among the very important parameters to be recorded for optimization purposes. Usually the drilling fluid density is measured through calibrated pressure sensors. Rheological properties on the other hand are still measured manually. The need for in situ measurement of rheological properties has been recognized and innovative solutions are forthcoming. This will make the online optimization process more accurate (Cayeux and Daireaux, 2009). Torque: This parameter is the torque of the drillstring while it is rotating. It is measured by means of TDS systems. Previously the readings for this parameter were relative. This parameter bears greater significance in deviated or horizontal wells than in vertical wells. MWD: In the late 1960s, the first Measurement While Drilling (MWD) equipment was developed, allowing for drillers to collect real-time data downhole. A present time, MWD offers the fastest growth in innovative technology and plays a central role in real-time optimization of a drilling process. LWD: LWD stands for Logging While Drilling. Formation related parameters could be captured during drilling and be used in the optimization process. LWD equipment was developed in the 1980s to allow collection of gamma, density, porosity, and resistivity formation measurements. Today, the MWD equipment is able to provide near real-time measurements such as azimuth, inclination, temperature, pressure, revolutions per minute (RPM), downhole torque on bit (TOB), weight on bit (WOB), downhole vibration, and bending moment. Significant advances have been made in this technology (Islam et al., 2018). However, current drilling optimization tools are not yet equipped with proper considerations of LWD. 2.2.5.2.2 Drilling optimization

The spectacular achievements in rotary drilling have been possible due to overall optimization of the drilling process. Optimization involves the entire drilling system, from the rig system, rotary table to drillstring and drill bits. In this process casings as well as cementing technology play a significant role. During 1950s, simultaneous improvements in

51

2.2 Drilling methods

understanding of the hydraulic principles, bit technology, and drilling fluid technology advanced knowledge in drilling technology. For instance, in 1952, the jet-type roller cone bits were invented. During that period, the first optimization program was envisioned by Graham and Muench (1959). They analytically evaluated the weight on bit and rotary speed combinations to derive empirical mathematical expressions for bit life expectancy and for drilling rate as a function of depth, rotary speed, and bit weight. Although rudimentary, it was a useful exercise for drilling optimization. In following years, it was recognized that each field ought to have its own set of constraints. Several drilling models were proposed in the past to explain the effects of drilling parameters, environment, and geology effect on the ROP. Significant research started in the end of the first half of the 20th century and the first models were based on R-W-N (ROP, WOB, and RPM) equations, mainly driven by empirical exponents multiplied by proportionality constants to take influencing variables into account, but, later, laboratory tests revealed that R-W-N equations showed reliable results only in case of perfect hole cleaning conditions. The evolution of these modeling started basically in 1960 with Cunningham (1960), followed by a chain of changes and further researches addressed by Maurer (1962), Galle and Woods (1964), Bingham (1965), Young Jr. (1974), and Warren (1981), actual and subsequent models were mainly based on further improvements on top of just-mentioned root ones. Apart from the BYM ROP model detailed in the subsequent chapters, the next equations below, by Galle and Woods (1964) model (1) and Warren (1981) model (2), are shown as a model comparison reference: ! ! 0 13 2 6 WOBksf ,4e ROP ¼ Cf ,



100 RPM2 sf



RPMb1 sf

B þ b2,RPMsf @1  e

0:92815,OD2bit þ 6,ODbit þ 1

p

2  RPMsf , WOBsf  ðWOBsf Þt ROP ¼ K, OD2bit ,S2



100 RPM2 sf

C7 A5 (2.1)

(2.2)

where b1 (dimensionless) is 0.75 or 0.428, for soft and hard formations, respectively; b2 (dimensionless) is 0.5 or 0.2, for soft and hard formations, respectively; p (dimensionless) is tooth wear coefficient; k (dimensionless) is coefficient accounting for WOB influence on ROP; Cf (dimensionless) is coefficient accounting for bit type, hydraulics, drilling fluid, and formation strength; and K (dimensionless) is constant dependent on drill-bit dullness and formation abrasiveness, as a consequence of drilling conditions. In early works, three parameters were identified as the most important ones in controlling a drilling process. They are: Rate of penetration (ROP), Weight on bit (WOB), and Rotation per minute (RPM). Great efforts are spent on modeling the interactions among these parameters. Several drilling models were proposed to explain the effects of drilling parameters,

52

2. State-of-the-art of drilling

environment, and geology effect on the ROP. The first half of the 20th century was devoted to empirical formulation. It was then followed up with experimental modeling. Experimental results showed that the major weakness of the model was the assumption of a straight hole. Such assumption, although typical of modern engineering, is inherently flawed in accounting for real-life factors at play (Khan and Islam, 2016). Instead of attempting to describe the proper physics of a real-life drilling process, coefficients were being tweaked in order to match predicted data with observed data. For instance, the early model of Cunningham and Eenink (1959), which essentially built on the assumption of straight hole, was followed by a chain of changes and further researches addressed by Maurer (1962), Galle and Woods (1964), Bingham (1965), Bourgoyne Jr. and Young Jr. (1974), and Warren (1981). The most notable contribution of the latter models was the introduction of a coefficient that worked much like a fudge factor. One of the most important drilling optimization studies performed was in 1974 by Bourgoyne and Young Jr. (1974). This model considers the effects of the depth, the characteristics of the formation being drilled, the drill-bit size, the mechanical factors of the drilling process (i.e., WOB and RPM), and the mud system properties, allowing each one to be adjusted by fitting coefficients. Starting with a linear drilling rate of penetration, they performed multiple regression analysis to select the optimized drilling parameters. This was followed with the use of a minimum cost formula, showing that maximum rate of penetration may coincide with minimum cost approach if the technical limitations were ignored. This simple but profound condition has been the driver of modern engineering, in which minimizing cost is the driver of a technology. The Bourgoyne and Young Jr. model consists of eight subfunctions, which affect the ROP. ROP is expressed as: ROP ¼ f 1,f 2,f 3,f 4,f 5,f 6,f 7,f 8

(2.3)

where f1 is effect of formation strength, f2 is effect of depth and compaction, f3 is effect of pore pressure, f4 is effect of differential pressure, f5 is effect of drill-bit diameter and WOB, f6 is effect of rotary speed, f7 is effect of drill-bit tooth wear, and f8 is effect of bit hydraulic jet impact force. Eq. (2.3) can be broken down into eight subequations as follows: f 1 ¼ e 2:303,a1

(2.4)

f 2 ¼ e 2:303,a2,ðTVDNTVDÞ

(2.5)

f 3 ¼ e 2:303,a3,TDV

0:69 ðEPPEPP

NÞ

f 4 ¼ e 2:303,a4,TVD,ðEPPECDÞ

(2.6) (2.7)

2.2 Drilling methods a5 WOBsf  ðWOBsf =ODbit Þt ODbit  f5 ¼  WOBsf  ðWOBsf =ODbit Þt ODbit N

 f6 ¼

PMPsf PMPsfN

Fj f8 ¼ ðFj ÞN

(2.8)

a6

f 7 ¼ ea7,h "

53

(2.9)

(2.10)

#a8 (2.11)

Where: TVD: True vertical depth [feet] TVDN: True vertical depth normalization value [feet] EPP: Actual equivalent pore pressure gradient [pounds/gallon] EPPN: Actual equivalent pore pressure normalization value [pounds/gallon] ECD: Actual equivalent circulating density [pounds/gallon] WOBsf: Surface measured weight on bit [kilopounds] ODbit: Drill-bit outside diameter [inches] (WOBsf/ODbit) N: Weight on bit over drill bit outside diameter normalization value [kilopounds/inch] RPMsf: Drill-string surface measured rotational speed [rotation per minute] RPMsf: Drill-string surface measured rotational speed normalization value [rotation per minute] ℎ: Drill-bit grading fractional tooth wear [dimensionless] Fj: Hydraulic jet impact force being applied beneath the drill bit [pounds] a1: Formation strength and drilling fluid properties coefficient [dimensionless] a2: Normal compaction trend coefficient [dimensionless] a3: Undercompaction and pore pressure coefficient [dimensionless] a4: Differential pressure coefficient [dimensionless] a5: Constant dependent on drilling conditions and WOB and drill bit curve behavior [dimensionless] a6: Constant dependent on drilling conditions and RPM curve behavior [dimensionless] a7: Tooth wear coefficient [dimensionless] a8: Hydraulic coefficient [dimensionless]. For the given subequations, normalization factors and coefficients are calculated through regression analysis using lower and upper limits of various coefficients. Following are further details of the coefficients along with their physical meanings.

54

2. State-of-the-art of drilling

1. Effect of formation strength is captured by f1. The expression of a1 primarily represents the effect of formation strength on the rate of penetration (ROP). There is no physical explanation for the exponential form of the expression, but mathematically any such expression accentuates the effect. This expression includes other effects than formation strength itself. Such effects are drilled solids, their rate of removal, etc. Such effects are embodied in the equation through regression analysis and hence are not separately modeled. 2. Effect of formation compaction is captured by f2. This term models the effect of compaction on ROP, assuming an exponential decrease in ROP with depth in a normally compacted formation. This assumption is simplified. The actual compaction is intricately related to the mode of deposition, which varies extensively in a petroleum reservoir. For scientific characterization of geological deposition, physical parameters such as the bulk density and porosity, soil strength, water infiltration rate, and evolution in aeration have to be factored in. Eventually, they also affect absolute permeability of the formation. 3. The effect of pore pressure on ROP is captured by f3. This term also models the effect of compaction on ROP, assuming exponential increase of ROP with the increased pore pressure gradient. f3 is actually related to f2 as they both include the effect of compaction. It is well known that formations, such as sandstones have higher ROP than formations, such as shale and limestone. Relatively, sandstones have the most ordered particles during sedimentation, followed by limestones and then shales. Historically, the role of particle distribution has been factored in indirectly through overburden stress and porosity. 4. The effect of differential pressure is captured by f4. This term represents the effect of pressure differential across the bottom of the hole on ROP. The differential pressure is caused by differential pressures due to mud density and formation pressure. The bottomhole pressure affects ROP negatively as cuttings are held back, thus increasing friction, which in turn causes bit teeth wear. It also decreases efficiency. 5. The effects of drill-bit diameter and WOB are captured by f 5. This term models the effect of drill-bit weight and diameter on penetration rate. Increased WOB has an exponential and proportional response on ROP. The relationship is not spontaneous, meaning the drilling process starts after a minimal applied load (WOB threshold). Past this WOB threshold value, a maximal point is attained, at which point foundering occurs. From this point on, the ROP WOB function reverses direction, resulting in the existence of an optimum operational value. This is shown in Fig. 2.9. As can be seen in this figure, foundering can be delayed and shifted to a higher value of applied WOB by reengineering. One way to do that is to optimize hydraulics (see f8). Also, note that the ROP is dependent on the hole diameters, for which ROP holds an inverse proportionality with hole diameter or bit size. 6. The effect of rotary speed is captured by f6. As shown in Eq. (2.9), this relationship assumes that the increased rotary speed is directly proportional and exponential to the penetration rate. Normally, after a maximum increased RPM (foundering point), it has a negative effect on ROP (past the inflection points in Fig. 2.9). Vibration plays a role as well, but is not directly accounted for in the equation.

2.2 Drilling methods

55

FIGURE 2.9 Traditional drill-rate curve highlighting optimum and maximum WOB regions (region II). Redrawn from Nascimento, A, Kutas, DT, Elmgerbi, A., 2015a. Mathematical modeling applied to drilling engineering: an application of Bourgoyne and young ROP model to a presalt case study. Mathematical Problems in Engineering 2015, 631290 and Nascimento, A., Kutas, D.T., Elmgerbi, A. et al., 2015b. An application of Bourgoyne and young ROP model to a presalt case study, Mathematical Modeling Applied to Drilling Engineering 2015, 9. https://doi.org/10.1155/2015/631290. Article ID 631290.

7. The effect of drill-bit tooth wear is captured by f7. Drill bits can be categorized by their cutting mechanisms, namely the roller-cutter-bit type and the fixed-cutter-bit or drag-bit type. The first one applies a mechanism of fracturing or crushing the formation and consists of two or more cones (normally three) which have the cutting elements attached to it and rotate about the axis of the cones as the drill bit rotates at the bottom of the hole. The second type has a mechanism of scraping (shearing) or grinding the formation being drilled, having as cutting elements, normally, natural or synthetic diamond (PDC drill bits) and consisting of fixed cutters in the blades that are integrated with the body of the drill-bit which rotates as a unit with the drill-string. As Eq. (2.10) shows, this term is exponential. The value of the coefficient a7 depends primarily on the drill-bit type. When carbide insert bits are used, penetration rate does not vary significantly with tooth wear. By contrast, milled tooth bits have more severe penetration rate decrease with wearing. Tooth wear is affected by formation abrasiveness, tooth geometry, bit weight, rotary speed, and the cleaning processes. 8. The effect of bit hydraulic jet impact force is captured with f8. Jet hydraulics are a function of fluid type used. A discussion on the drilling fluid system is forthcoming in a latter section. It suffices to say each drilling fluid system has its specific design criteria and inherent advantages and shortcomings. Fluid selection is based on specific needs of a formation. They are mainly divided into four main system types: freshwater, saltwater, oil-synthetic-based, and pneumatic. Typically, selection of a fluid system undergoes the following sequential screening 1: technical feasibility; 2. Costs; 3. Environmental impact; and 4. Performance optimization. As we will see in latter section, this sequence is not conducive to sustainable development. Mechanically, increased jet force implies better cleaning of cuttings around the drill-bit teeth on the bottom of the hole and also better hydraulic environment for cutting transportation to the surface by maintaining the whole area around the drill-bit and drill-string more

56

2. State-of-the-art of drilling

clean. This can in turn help avoid differential sticking and decrease friction. Warren (1981) found in his microbit experiments that ROP is proportional to a Reynolds number group and that increased Reynolds number can increase the ROP. Moreover, McLean (1964) and Warren (1984) experimentally showed how the drill-bit jet impact force could positively influence the ROP. This term had been normalized to be equal to 1.0 for a jet impact of 1000 [lbf]. All parameter values are listed in Tables 2.5 and 2.6. This model has been proven to be pivotal in bringing the drilling technology to the Information age, in which this model has been fitted with MWD and logging-while-drilling (LWD) and other technologies of real-time monitoring. Fig. 2.10 shows overall development of new technologies related to optimizing rotary drilling. As can be seen in this figure, real-time drilling optimization began in the 1980s. In 1990s different drilling planning approaches were brought to surface. For instance, Bond et al. (1998) presented an alternative planning approach to the drilling and completion process. Three new wells and six subsea completions were finished 20% under budget with this tool and with a simple philosophy characterized by the following questions. - What is current performance? - What is possible? - What is needed to get there?

TABLE 2.4

Comparison of conventional downhole telemetry systems. Mud-pulse telemetry

Electromagnetic telemetry

Acoustic telemetry

Time to collect Data

2e7 min

150 h recording time) with continuous high-frequency data capture (1000 Hz). It also supports remote technical analysis anytime, anywhere, thus making the dynamic optimization one step closer to reality. 4. MWD economics: Fig. 2.11 shows the steady improvement of rig performance that has occurred as crews become adept at using and understanding this electronic equipment

FIGURE 2.11 A conceptual graph illustrating phases of improvement in drilling technologies and equipment. (1: Experienced crew; 2: Crew with electronic surface equipment; 3: Drilling as manufacturing; 4: MWD improvement; 5: M/LWD improvement; 6: Surface equipment improvement.)

64

2. State-of-the-art of drilling

Clearly transparency in drilling data and faster processing translate into improvement, resulting in economic benefits. While surface measurements, such as, various boundary effects from torque and drag alongside the drillstring, torsional drillstring wrapping, and drilling dysfunctions such as stick/slip, balling, and whirling, subsurface data help making the whole drilling picture clear, thus enhancing the drilling optimization process. Overall, downhole data collection has resulted in an overall decrease in the time and cost to drill a well. As shown in Fig. 2.5, taking standard measurements such as inclination, azimuth, and temperature can result in an increased ROP of 32% due to increased knowledge of downhole conditions (Pastorek et al., 2019). These measurements allow for the required directional measurements without the need for trips in and out of the well. When combined with semiadvanced data, such as pressure-while-drilling data, an operation can further improve ROP by an estimated 10%e15% (Bhattacharjee, 2014). Finding the optimum drilling parameters, such as RPM and WOB, is crucial to improving Rates of Penetration, ROP. However, the relationship being strictly nonlinear and having other factors, including intangibles (such as, footage drills, downhole tool life, vibration control, durability, and steerability) make the process of optimization quite intricate. In this process, mud quality plays a pivotal role. It is the mud system that affects the debris removal, thereby creating a pivot in the drilling process. Linked with the mud system is the rig system itself. The rig system is linked with the system hydraulics. On the subsurface side, the most important factor is the rock. The rock characteristics, which are extremely variable, highlight the need for depicting formation with as much clarity as possible. Table 2.5 shows how drilling data are sought with different goals in different countries. For each case, the results are summed up in monetary savings. Properly analyzing drilling performance to create sustainable, practical, engineering solutions requires quality measurements. The ability of a driller to collect and interpret vast amounts information (e.g., through both tangible and intangible data, such as sight, smell, sound, vibration) has allowed wells to be drilled without complex data collectiondalthough with variable and sometimes unpredictable results. Table 2.8 illustrates the need for continuous improvement in measurements and instruments. 4. Miniaturized Sensors: Recent innovations have produced an array of products, using Fit for Micro-Electro-Mechanical Systems (MEMS). Halliburton (e.g., Roddy, 2008) led the way by introducing MEMS for both well stimulation and drilling applications. The wellbore environment is very challenging to the sensors, whose inherent characteristics are not conducive to being effective in such an environment. For example, lowpowered (e.g., nanowatt) electronic moisture sensors are available, but have inherent limitations in the subsurface environment. For instance, when embedded within cement, the highly alkali environment can damage their electronics, and they are sensitive to electromagnetic noise. Additionally, power must be provided from an internal battery to activate the sensor and transmit data, which increases sensor size and decreases useful life of the sensor. Roddy (2008) invention involves placing a sealant composition comprising one or more MEMS sensors in a wellbore and allowing the sealant composition to set.

2.2 Drilling methods

65

TABLE 2.8

Cost/time benefits of using downhole technology.

Location

Goal

Result

Gulf of Thailand

To drill in an environment with static temperatures up to 200 C.

Using Schlumberger’s TeleScope ICE ultraHT MWD, drillers were able to successfully complete the well, saving 12 h of operating time worth an estimated $167,000.

Persian Gulf

To minimize shock and vibration during drilling.

Using a specialized BHA and Schlumberger’s PowerPulse MWD, drillers were able to save 6 days of operating time. This resulted in a savings of $744,000.

Russia

To reduce drilling time and cost in a horizontal well.

By replacing their mud motor with an advanced BHA and MWD system, drillers were able to increase ROP by 56%, saving 5 days of operating time.

Sakhalin To complete two wells in a short Island, Russia timeframe.

Using a rotary steerable system and advanced M/LWD tools, drillers were able to save 7.5 days of operating time. This resulted in a savings of $600,000.

Kuwait

To reduce shock and vibration in an environment with high compressive rock strength.

Using Schlumberger’s shock sub tool, the operation was able to increase ROP by 50%.

Russia

To collect real-time data in a high-pressure horizontal formation.

Using M/LWD technology, drillers were able to save 13 days of operating time and increased ROP by 30%.

Eagle Ford Shale Play

To reduce drilling time and cost using directional measurements.

Using MWD technology to record real-time directional readings, drillers were able to save 4 days of operating time, a 30% savings.

Kazakhstan

To drill four wells while acquiring M/LWD data.

Using an M/LWD, a rotary steerable system, and high-performance drill bits, this operation was able to save 12 days of operating time with zero NPT.

Negros Island, To drill a vertical well and increase ROP. Philippines

Using a mud motor and Scientific Drilling’s Falcon MWD, drillers were able to increase ROP by 50% and decrease drilling time by 66%.

Williston Basin, United States

To drill horizontal wells while increasing efficiency and eliminating NPT.

Using Scientific Drilling’s Falcon MWD, drillers were able to reduce the cost per foot to $130, a 40% cost savings when compared to similar wells.

Russia

To drill a vertical well in an HTHP environment.

Using Schlumberger’s PowerPak steerable motor and SlimPulse MWD, drillers were able to finish with an inclination of 0.25 and increased ROP by 25%.

From Schlumberger.

This initiative was followed up by a patent by Halliburton (Roddy et al., 2012), which involved placing a wellbore composition comprising a plurality of Micro-Electro-Mechanical System (MEMS) sensors in the wellbore. Also added is a plurality of acoustic sensors in the wellbore and a data processing tool all from an interior of the wellbore to an exterior of the wellbore. The system is powered by a turbo generator or a thermoelectric generator located in the wellbore.

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2. State-of-the-art of drilling

Baker-Hughes made similar efforts in developing MEMS, suitable for wellbore monitoring. Taylor (2009) invention involves a device with at least one radio frequency identification device (RFID) into a fluid configured to be disposed in the borehole; and a collection unit configured to receive at least a portion of the fluid, the collection unit comprising a detector that detects at least one of the at least one RFID and data contents thereof; wherein the detector provides output for estimating the parameter. A method for estimating a parameter of a borehole is also disclosed. Although the patent application was abandoned, this invention shows avenues to improve wellbore data collection. A recent patent application filed by Bridgestone highlights some future opportunities for drilling monitoring (Merat et al., 2019). This is a sensor system for obtaining data from an elastomeric article, which includes at least one wireless sensor. The sensor length-scales range from nano- to micro-scale devices. The article may include sensors embedded within one of the materials of the article, a layer of sensors built into the article, and a string of sensors disposed within a component or embedded within a component of the article. The sensors may be configured to provide data related to one or more of temperature, pressure, sidewall flex, stress, strain, and other parameters. The sensors may be LCD sensors, conductive polymer sensors, biopolymer sensors, and/or polymer diodes suitable for sensing data during the operation of the tire. This system can be adapted to downhole applications. 5. Overall innovations: Table 2.9 shows latest innovations of Halliburton, all from 2013.

2.3 Drilling fluids Drilling fluid (also called drilling mud) is an essential part in the rotary drilling system. The quality of drilling fluids system dictates the effectiveness of a drilling project. The cost of the drilling mud itself is not very high. However, the fluid system plays a pivotal role for both technical effectiveness and long-term environmental impact, and the fluid system can prove to be costly and pivotal to sustainability. The correct selection, properties, and quality of mud is directly related to some of the most common drilling problems such as rate of penetration, caving shales, stuck pipe, and loss circulation (Fig. 2.12). In addition, the mud affects the formation evaluation and the subsequent efficiency of the well. More importantly, some toxic materials are used to improve the particular quality of the drilling fluid, which is a major concern of the environmentalist. This addition of toxic materials contaminates the underground system as well as the surface of the earth.

2.3.1 Drilling fluid circulating system Different parts of rig are involved to complete the fluid flow channel. Fig. 2.13 shows a complete flowchart of different components that are involved with circulating system. The mud, water, and other necessary chemicals, and solids are mixed in the mud mixing tank. Then mud goes to the fresh mud pit from where it is pumped to the bottomhole assembly. Mud passes through standpipe, hose and swivel, kelly, and then drillpipe, drill collar to drilling bit. On return, mud with cuttings pass through annulus, BOP, channel, shale shaker, desander to desilter to again the mud pit in surface. The use of mud during the drilling

TABLE 2.9 Innovations reported by Halliburton. Future applications

High strength dissolvable structures for use in a subterranean well Patent number: 8434559

A well tool can include a flow path, and a flow blocking device which selectively prevents flow through the flow path. The device can include an anhydrous boron compound. A method of constructing a downhole well tool can include forming a structure of a solid mass comprising an anhydrous boron compound, and incorporating the structure into the well tool.

1. Downhole separation. 2. Natural sourcing of boron compounds. 3. Similar compounds involving silicon and carbon (Jemmis and Jayasreem, 2003).

Methods and Systems of Formation Density Measurements in the Presence of Invasion of Drilling Fluids Publication number: 20130110404

Formation density measurements in the presence of invasion of drilling fluids. Methods include: irradiating a formation with gamma ray, wherein drilling fluid has invaded the formation. It determines information such as a standoff, formation porosity, formation density prior to invasion by the drilling fluid, and radial depth of invasion of the drilling fluid into the formation.

1. Natural gamma ray sources. 2. extension of the technique to include formation texture, toughness, and composition.

Safety valve with electrical actuator and tubing pressure balancing Publication number: 20130105149

1. Opens up opportunities for dynamic A well tool for use with a subterranean well can include a flow control. passage extending longitudinally through the well tool, an 2. Future study should include internal chamber containing a dielectric fluid, and a flow path interactions with drilling fluid and which alternates direction, and which provides pressure possible use in conjunction with communication between the internal chamber and the flow sonic tools. passage. A method of controlling operation of a well tool can include actuating an actuator positioned in an internal chamber of the well tool, a dielectric fluid being disposed in the chamber, and the chamber being pressure balanced with a flow passage extending longitudinally through the well tool, and varying the actuating, based on measurements made by at least one sensor of the well tool.

Construction and operation of an oilfield molten salt battery Publication number: 20130106366

1. Alternate material for battery salt. Construction and operation of an oilfield molten salt battery. A 2. Novel charging technique (relying battery includes an outer case, an elongated mandrel positioned within the outer case, and the mandrel being an electrical on nonelectrical natural sources). component of the battery. Another battery includes an electrical pickup, and a polymer insulator providing insulation between the outer case and the pickup. A method of charging a battery for use in a subterranean well includes the steps of: providing the battery including an electrolyte, and anode and cathode electrodes, the electrolyte being a molten salt comprising lithium salt, and at least one of the electrodes comprising lithium atoms; positioning the battery within a wellbore; and then charging the battery. Another method includes the steps of: heating the lithium ion molten salt battery; then charging the battery; and then positioning the battery within a wellbore. (Continued)

67

Description

2.3 Drilling fluids

Invention title and number

68

TABLE 2.9 Innovations reported by Halliburton.dcont’d Description

Future applications

Method and Apparatus for Sensing Elongated Subterranean Anomalies Publication number: 20130105224

A system of various LWD systems that provides resistivity logging coupled with deep detection of elongated anomalies at acute angles, enabling effective geosteering without disrupting drilling operations and without requiring intervention in the operations of the existing well. One LWD system embodiment employs a tool having tilted antennas as the transmitter and the receiver, where at least one of the antennas is placed in the vicinity of the bit, making it possible to detect existing wells at distances of 50e100 feet. In some cases, the detection distance is increased by enhancing the visibility of the existing well using a contrast fluid treatment on target well, either to fill the bore or to surround the well with treated cement or fluids that invade the formation. At least one inversion method separates the inversion of formation parameters from the inversion of parameters specifying distance, direction, and orientation of the existing well.

1. Realtime reservoir characterization; 2. Coupling with novel logging tools; 3. Nonlinear inversion of data to determine the cloud points.

Nanoparticle Smart Tags in Subterranean Applications Publication number: 20130109100

The system involves smart tagging nanoparticles in order to detect a particular analyte in real time. One embodiment of the present invention provides a method of providing a drilling fluid having a nanoparticle smart tag; and a base fluid; and introducing the drilling fluid in a subsurface geologic formation that has an analyte.

1. Extension to other types of nanoparticles; 2. compositional analysis of innate fluids; 3. Real-time rock and fluid characterization.

Method and System of Determining a Parameter Associated with a Formation Corrected for Neutrons Produced Publication number: 20130105680

The process determines a parameter associated with a formation corrected for neutrons produced. Methods include: disposing a logging tool within a borehole, producing neutrons by a neutron source within the logging tool, detecting neutrons produced by the neutron source, the detecting by a neutron detector; creating an indication of a number of neutrons produced by the neutron source, the indication based only on neutrons detected that have not interacted with other elements before entering the neutron detector, obtaining a count rate of a gamma detector responsive to the production of neutrons by the neutron source and determining a parameter associated with the formation based on the count rate and on the indication of the number of n eutrons produced.

1. Natural isotopes, both stable and unstable kids in their natural state. 2. Combination with other tools, including sonic. 3. New filtering tools.

2. State-of-the-art of drilling

Invention title and number

High intensity Fabry-Perot sensor Patent number: 8432552

It is a sensor assembly having an optical fiber, a lens in optical communication with the optical fiber, a reflective surface spaced from the lens, for reflecting light from the beam back to the lens, a partially reflective surface positioned between the reflective surface and the lens. Other parts of the innovation includes partially reflective surface for reflecting light from the beam back to the lens, and an alignment device for aligning the lens and reflective surface with respect to one another, such that light from the beam of light transmitted from the lens reflects from the reflective surface back to the lens. The alignment device can have a rotational component and a base component, where the rotational component rotates to align a beam of light transmitted from the lens. The rotational component can also cooperate with the base component to move axially with respect to the reflective surfaces to align the beam for optimum power.

High strength dissolvable structures for use in a subterranean well Patent number: 8430173

A well tool can include a flow path, and a flow blocking device 1. Use of silicon and carbon as a which selectively prevents flow through the flow path. The device substitute to boron. can include an anhydrous boron compound. A method of constructing a downhole well tool can include forming a structure of a solid mass comprising an anhydrous boron compound, and incorporating the structure into the well tool.

Anhydrous boron-based timed delay plugs Patent number: 8430174

A well tool for use with a subterranean well can include an elongated passageway and a plug which prevents fluid communication through the passageway for a predetermined period of time. The plug can include an anhydrous boron compound, whereby the predetermined period of time is determined by a length of the anhydrous boron compound. A method of operating a well tool in conjunction with a subterranean well can include exposing an anhydrous boron compound to an aqueous fluid, with the anhydrous boron compound being included in a plug which prevents fluid communication through a passageway of the well tool. The well tool can be operated in response to fluid communication being permitted through the passageway a predetermined period of time after the exposing step.

1. Natural chemicals for paints as well as fiber material; 2. data transfer of sonic and other data; 3. Local electricity generation for charging gadgets.

2.3 Drilling fluids

1. Natural substitutes to processed boron compounds.

(Continued)

69

Description

Hydrajetting Nozzle and Method Publication number: 20130098043

A jetting device comprises a body, and an interior flow path within the body. The interior flow path comprises a flow section, an expansion section, and a shoulder formed at the intersection of the flow section and the expansion section. The length and diameter of the expansion section are configured to allow a portion of the pressure of the fluid downstream of the expansion section to provide power to a fluid flowing through the nozzle when the fluid is flowing through the nozzle.

Fluid Resistivity Sensor Publication number: 20130099808

Various embodiments include apparatus and methods of determining resistivity of fluids downhole in a well. The apparatus and methods may include using a sensor that employs a focused electric dipole as a transmitter and a uses a receiver to detect the electric current strength in the fluid under measurement responsive to the transmitter. Additional apparatus, systems, and methods are disclosed.

Novel High Density Brines for Completion Applications Publication number: 20130098615

Clear, high density brine for use completion operations in a subterranean formation for the recovery of hydrocarbons. The brine comprises an ionic compound selected from the group consisting of zinc iodide, strontium bromide, strontium iodide, cerium bromide, cerium iodide, cerium chloride, lanthanum bromide, lanthanum iodide, lanthanum chloride, and mixtures thereof. The brine may also advantageously be used as the internal phase of invert emulsion drilling fluids.

Magnetically controlled delivery of subterranean fluid additives for use in subterranean applications Patent number: 8424598

Methods for providing controlled delivery of subterranean fluid additives to a well bore treatment fluid and/or a surrounding subterranean environment using intelligent materials that respond to a magnetic stimulus to release subterranean fluid additives downhole in a subterranean environment. The methods include releasing a subterranean fluid additive in a subterranean formation including providing a magnetically sensitive component that includes a subterranean fluid additive; providing a magnetic source; and releasing the subterranean fluid additive in the subterranean formation from the magnetically sensitive component using a magnetic force generated from the magnetic source.

Future applications

2. State-of-the-art of drilling

Invention title and number

70

TABLE 2.9 Innovations reported by Halliburton.dcont’d

A downhole power generator has a substantially tubular body. A cover surrounds at least a portion of the body. At least one piezoelectric element is disposed in a cavity in the body, the piezoelectric element acting cooperatively with the cover such that motion of the cover relative to the body causes the piezoelectric element to generate electric power. A method for generating power downhole comprises disposing a cover around at least a portion of a substantially tubular body; disposing at least one piezoelectric element in the body; and engaging the piezoelectric element with the cover such that motion of the cover relative to the body causes the piezoelectric element to generate electric power.

Downhole monitoring with distributed acoustic/vibration, strain and/or density sensing Publication number: 20130091942

Distributed acoustic, vibration, density and/or strain sensing is utilized for downhole monitoring. A method of tracking fluid movement along a wellbore of a well includes: detecting vibration, density, strain (static and/or dynamic) and/or Brillouin frequency shift in the well using at least one optical waveguide installed in the well; and determining the fluid movement based on the detected vibration, density, strain and/or Brillouin frequency shift. Another method of tracking fluid movement along a wellbore of a well includes: detecting a change in density of an optical waveguide in the well; and determining the fluid movement based on the detected density change.

High-resolution wireline nuclear magnetic resonance tool Patent number: 8421454

A nuclear magnetic resonance well logging tool, where some embodiments comprise two, oppositely oriented magnets separated by a pole piece to guide static magnetic flux into a sensitive volume, and another pole piece serving as a core for several antennas. For some embodiments, the antennas are solenoids. Two of the antennas serve as transmit and receive antennas, where they are driven to generate an elliptically polarized magnetic field, and their antenna responses are combined so that the combined response is sensitive to elliptically polarized magnetic fields, but with zero gradient in the z-direction. A third antenna serves as a receive antenna sensitive to magnetic field vectors having a sinusoidal spatial variation in the z-direction of period equal to the length of the third antenna. A fourth antenna serves as a receive antenna sensitive to sinusoidal magnetic field vectors with the

2.3 Drilling fluids

Apparatus and method for generating power downhole Patent number: 8426988

71

(Continued)

Invention title and number

Downhole sources having enhanced ir emission Publication number: 20130087723

Description

Method and apparatus for making resistivity measurements in a wellbore Publication number: 20130088364

Abstract: During drilling of an earth borehole, resistance measurements may be made at the drill bit through use of a bottom hole assembly that includes a drill bit having a sensor, such as an electrode, located generally at an exterior surface of the drill bit. The current will be induced in the formation from multiple transmitters, at least one of which will be supported on, or very close to the drill bit. Connection mechanisms are described that enable the releasable engagement of electrical conductors to circuitry within the drill bits. The obtained resistivity measurements at the drill bit can be used for many purposes, including formation imaging and geosteering of the drilling operation.

Multiple distributed force measurements Patent number: 8407006

Abstract: Methods, computer programs, and systems for detecting at least one downhole condition are disclosed. Forces are measured at a plurality of locations along the drillstring. The drillstring includes a drillpipe. At least one of the forces is measured along the drillpipe. At least one downhole condition is detected based, at least in part, on at least one measured force.

Future applications

2. State-of-the-art of drilling

same spatial-frequency as the third antenna, but phase shifted by 90 degrees. Light sources are provided with enhanced low-frequency (e.g., near infrared) emission. Some disclosed embodiments include a filament and at least one re-radiator element. The filament heats the re-radiator element to a steady-state temperature that is at least one quarter of the filament’s absolute temperature. As disclosed herein, the increased surface area provided by the re-radiator element provides enhanced IR radiation from the light source. Patterning or texturing of the surface can further increase the reradiator element’s surface area. Various shapes such as disks, collars, tubes are illustrated and can be combined to customize the spectral emission profile of the light source. Some specific embodiments employ a coating on the bulb as the re-radiator element. The coating can be positioned to occlude light from the filament or to augment light from the filament, depending on the particular application. The various re-radiator elements can be positioned inside or outside the bulb.

72

TABLE 2.9 Innovations reported by Halliburton.dcont’d

2.3 Drilling fluids

73

FIGURE 2.12 Impact of downhole data collection (and use) on ROP. (Standard services: directional data plus temperature; Intermediate services: standard data plus pressure; Advanced services: Intermediate plus LWD plus Drilling Mechanics data).

FIGURE 2.13

A block diagram for drilling fluid circulating system.

operations is very crucial. As a result, water was used as the first drilling fluid in France in 1845. The purpose of this use was to bring the cuttings from the borehole to the surface. However, the diverse applications of drilling fluid make it a prime requirement for the rotary drilling. The primary functions of the drilling fluid are to: i. Remove and transport cuttings from bottom of the hole to the surface through annulus (i.e., clean the borehole from cuttings and removal of cuttings). ii. Exert sufficient hydrostatic pressures to reduce the probability of having a kick (i.e., control of formation pressure).

74

2. State-of-the-art of drilling

iii. Cool and lubricate the rotating drillstring and drilling bit. iv. Transmit hydraulic horsepower to the bit. v. Form a thin, low permeable filter cake to seal and maintain the walls of the borehole and prevent formation damage (i.e., seal the thief zones). vi. Suspend drill cuttings in the event of rig shutdown so that the cuttings do not fall to the bottom of hole and stick to the drillpipe. vii. Support the wall of the borehole. viii. Maintain wellbore stability (i.e., keep new borehole open until cased). In addition to the above functions, there are some other secondary functions such as suspending the cuttings in the hole and dropping them in surface disposal areas, improving sample recovery, controlling formation pressures, minimizing drilling fluid losses into the formation, protecting the soil strata of interest (i.e., should not damage formation), facilitating the freedom of movement of the drillstring and casing, and reducing wear and corrosion of the drilling equipment, and provide logging medium. It is noted that the following side effects must be minimized to achieve the above functions. i. Damage to subsurface formation, especially those that may be productive ii. Loss of circulation iii. Wash and circulation pressure problems iv. Reduction of penetration rate v. Swelling of the sidewalls of the borehole creating tight spots and/or hole swelling shut vi. Erosion of the borehole vii. Attaching of the drillpipe against the walls of the hole viii. Retention of undesirable solids in the drilling fluid ix. Wear on the pump parts

2.3.2 Classification of drilling fluids Drilling fluids are generally classified according to their base composition. It may be broadly classified as liquid, gases, and liquid-gas mixtures. Although pure gas or gas-liquid mixtures are used, they are not as common as the liquid-based systems. A detail classification of drilling mud is shown in Fig. 2.14. Drilling fluids can also be broadly categorized as compressed air, foam, clear water, water-based mud, and oil-in-water emulsion or oil-based mud. In addition to the above, additives must often be added to these fluids to overcome specific downhole problems. A freshwater or saltwater-based drilling fluid with additives is commonly called drilling mud. Based on some specific requirements and functions, some special types of drilling fluids are made which will be discussed as a separate subsection below. Air and water generally satisfy the primary functions of a drilling fluid. In addition, chemical additives are used for specific purposes. The main factors that govern the selection of drilling fluids are (1) formation type to be drilled, (2) the range of formation data, i.e., pressure, temperature, permeability, saturation, and strength, (3) the formation evaluation procedure used, (4) the water quality available, i.e., fresh or saline water, and (5) ecological and

2.3 Drilling fluids

FIGURE 2.14

75

Classification of different drilling fluids.

environmental considerations, i.e., sustainability analysis. However, the drilling fluid that yields the lowest drilling cost in an area must be determined by trial and error. The following sections describe the different drilling fluids in detail. 2.3.2.1 Water-based mud Water is the most common fluid. When the solids are entrained in the water it makes it a natural mud. Water-base mud (WBM) is defined as a drilling mud in which the continuous phase is water. WBM is the most commonly used drilling fluid worldwide, although in the North Sea oil-base muds are the most widely used type of mud. WBM are those drilling fluids in which the continuous phase of the system is water. WBM has some advantages: (1) Some clays hydrate readily in water and hence due to clay hydrate in water, it greatly increases the viscosity of the mud which helps carry the rock cuttings to the surface, (2) clay particles form mud cake which reduces water loss (less lost circulation), and prevents the wall from caving into the hole (by forming a mud cake, i.e., less formation damage, and (3) less mud cost (mud cost ¼ 10% of well cost). However, there are some disadvantages as well: (1) reduction in penetration rate, (2) increase in pressure loss due to friction. In small holes, the disadvantages may be more than the advantages. So equipment to remove finely divided solids must be used to prevent formation of natural clays. There are two types of waterdsalt water and fresh water used as base composition for WBM. A fresh water mud is one in which the continuous liquid phase of the system is fresh water. Salt water drilling fluids are prepared from brine water, seawater, and dry sodium chloride or other salts such as potassium chloride. These fluids have a chloride content of 6000 mg/L to less 189,000 mg/L. The commonly used products are attapulgite, PAC, CMC, and starch to increase viscosity and FCLS, caustic lignite to control gel strength and filtrate loss. An inhibited mud is a mud with salt or calcium to reduce active clays’ hydration. An inhibited mud is one where the reactivity of the water phase within the mud system with active clays within the formation is greatly reduced. The distinction between fresh-water and inhibited muds is based on salt concentration. Inhibited muds are used when a problem arises during drilling with fresh mud (sloughing clays). Fresh water muds are those having less than 3000 ppm Naþ ions. It is used to drill shale and clay formations. Low solid muds are those where solid contents are less than 5%.

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2.3.2.2 Oil-based mud Oil-base mud (OBM) is defined as the drilling mud made with oil as the solvent carrier for the solid content. OBM is a drilling fluid in which oil is the continuous phase and where water content is less than 2% to up to 5%. This water is spread out, or dispersed, in the oil as small droplets. In general, diesel, kerosene, and fuel oils are used as base fluid. OBMs are used for a variety of applications where fluid stability and inhibition are necessary such as high-temperature (>2000 F), and deep (>16,000 ft) wells, salt and unconsolidated formation and soft shale formation where sticking and hole stabilization is a problem. Using OBM results in fewer drilling problems and causes less formation damage than WBMs and they are therefore very popular in certain areas. OBM is normally used in extremely hot formations and when water-base muds adversely affect formation. In general, OBMs are applied in directional wells and horizontal wells. It is also used to drill and core (i.e., collection of samples for analysis) pay zones, to drill troublesome formations (i.e., shale), and to reduce corrosion. OBMs consist of three types: (i) invert emulsion oil-based mud, (ii) pseudo oil-based mud, and (iii) full oil mud. The ratio of oil to water or brine is 50:50 to 80:20. Various chemicals, such as surfactants, organic clay and asphalt are used to control rheological, filtration, and emulsion stability. OBMs are formulated with only oil as the liquid phase and water content is less than 5%. These types are used as coring fluid or for hostile environment. OBMs require higher additional gelling agents for viscosity, such as emulsifiers and wetting agents. OBMs are however more expensive and require more careful handling (i.e., pollution and toxicity control) than WBMs. It is useful in drilling certain formation that may be difficult or costly to drill with water-based mud. OBM has some advantages and disadvantages that are as follows: Advantages: 1. Good rheological properties at temperatures as high as 500 F 2. More inhibitive than inhibitive water-based muds 3. Effective against all types of corrosion 4. Superior lubricating characteristics 5. Permits mud densities as low as 7.5 lbm/gal Disadvantages: 1. Generally more expensive and higher initial cost 2. Require more stringent pollution-control procedures 3. Reduced effectiveness of some logging tools 4. Remedial treatment for lost circulation is more difficult 5. Detection of gas kicks is more difficult because of gas solubility in diesel oil (i) Invert emulsion oil-based mud: invert emulsion drilling fluids are water in oil emulsion, typically with CaCl2 brine as the emulsified phase and mineral oil as the continuous phase.The basic components of a typical low toxicity invert emulsion fluid are base oil, water, emulsifier, wetting agents, organophilic clay, and lime. Only low toxic base oil should be used within the range as mentioned earlier. This is the external emulsion phase. Water is used as an internal emulsion phase which gives the oil/water ratio (OWR). OWR gives the percentage of each part as a total

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of the liquid phase. Generally, a higher OWR is used for drilling troublesome formations. The salinity of the water phase can be controlled by the use of dissolved salts, usually calcium chloride. Control of salinity in invert oil muds is necessary to tie-up free water molecules and prevents any water migration between the mud and the open formation such as shales. (ii) Pseudo oil-based mud: it is biodegradable synthetic base oil mud. The developments such mud has been made to help the environmental problem of low toxicity oil-based muds and their low biodegradability. A system which uses synthetic base oil is called a pseudo oil-based mud (SOB). Synthetic oil-based mud is defined as a mud with the oil component replaced by lower toxicity oil such as mineral oil. It is designed to behave as close as possible to low toxic oil-based mud (LTOBM). It is built in a way similar to normal oil-based fluids using modified emulsifiers. SOB muds are expensive systems and should only be considered in drilling hole sections that cannot be drilled using water-based muds without the risk of compromising the well objectives. The base oils that are being used in this type of mud are the detergent alkalates, synthetic hydrocarbon, ether, and ester. Synthetic base fluids include linear alpha olefins (LAO), Isomerized olefins (IO), and normal alkanes. Other synthetic base fluids have been developed and discarded such as ethers and benzene-based formulations. Esters are nonpetroleum oils are derived from vegetable oils. They contain no aromatics or petroleum-derived hydrocarbons. The primary advantage of an ester-based fluid is that it biodegrades readily, either aerobically, or, more importantly, from a mud cuttings disposal viewpoint, anaerobically. (iii) Full-oil mud: it has very low water content (180.0

>10.5

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present at elevated levels in some geographical locations. Soda ash (i.e., Na2CO3) is used in water-based muds as a source of carbonate ions to precipitate calcium, increase pH, or flocculate spud muds. It is a weak base which is soluble in water and dissociates into sodium (Naþ ) and carbonate (CO2 3 ) ions in solution. The chemical reaction of calcium/magnesium precipitation can be described as: Caþ2 or Maþ2 þ Na2 CO3 / CaCO3 or ðMaCO3 ÞY þ Naþ

(2.30)

2.3.7.11 Water analysis Water analysis of mud is necessary because the existence of chemical content may affect the selection of the mud type. Invasion of water and soluble salts may change the properties of the mud in drilled formations. Usually the simple tests for alkalinity, chloride, and hardness serve to identify any objectionable contaminants from water. Occasionally, a more detailed analysis is needed that are available in literature. 2.3.7.12 Chemical analysis The chemical analysis is an important test to find out the concentration of different ions exists in drilling mud. These analyses may be used for formation identification, compatibility studies, quality control, or evaluation of pollution problems. The concentration of hydroxyl (OH ), chloride (Cl ), sulfides (S2 ), potassium (Kþ ), formaldehyde (CH2 O), etc., are required to control for quality mud which is an API standard. The test kits contain all chemicals, equipment, and glassware for measurement in the field. For results of these analyses to be accurate and reliable, care must be exercised in taking the drilling fluid samples. Most chemical analyses are performed on the drilling fluid filtrate rather than the drilling fluid. To obtain a sample of drilling fluid filtrate, the drilling fluid is filtered using a standard API, 100 psi (690 kPa) filter press, or a high temperature high pressure filter press. This operation removes all solids but leaves the dissolved salts. Some filtrates are so darkly colored the filtration endpoints cannot be seen. Literature shows that certain chemical analyses are useful in the control of mud performance. For example, an increase in chloride content may adversely affect mud properties unless the mud has been designed to withstand contamination by salt. The detailed analysis is available in API RP 13B. 2.3.7.13 Chloride concentration The amount of chloride (Cl ) in the mud is a measure of the salt contamination from the formation. Chloride concentration increases due to the entrance of salt and subsequently contaminates the mud system. This situation arises when a salt formation is drilled or saline formation water enters the wellbore. The Cl concentration is determined by titration with silver nitrate (AgNO3 ) solution. This procedure causes the Cl to be removed from the solution as AgCl, a white precipitate. The chemical reaction is obtained as: Agþ þ Cl /AgClY

(2.31)

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The endpoint of the titration is identified using a potassium chromate ðK2 CrO4 Þ indicator. The excess Agþ present after all Cl has been removed from solution reacts with the chromate (CrO2 4 ) to form Ag2 CrO4 which is an orange-red precipitate. The chemical reaction is obtained as: Agþ þ CrO2 4 /Ag2 CrO4 Y

(2.32)

The above procedure involves taking a small sample of filtrate, adding phenolphthalein and titrating with acid until the color changes. Add 25e50 mL of distilled water and a small amount of potassium chromate solution. Stir continuously while silver nitrate is added drop by drop. The end point is reached when the color changes. The chloride content is calculated from: Cl content in ppm ¼

ml of AgNO3 ml of filtrate sample

(2.33)

2.3.7.14 Cation exchange capacity of clays The clay content of a drilling fluid has the ability to exchange free cations located in the aqueous solution. A well-known application of the ion exchange reaction is the softening of water. Ion exchange reactions in the drilling fluids are important because the ability of the clay particles to hydrate depends greatly on the presence of free cations. The ability of one cation to replace another depends on the nature of the cations and their relative concentrations. The common cations will replace each other when present in the same concentration in the order as shown by Eq. (2.34): Al3þ > Ba2þ > Mg2þ > Ca2þ > H þ > Kþ > Naþ

(2.34)

However the order as shown in Eq. (2.34) can be changed by increasing the concentration of the weaker cation presence. Many organic compounds also absorb in clay structures. Methylene blue is a dye. If it is allowed to dry on glassware or other laboratory equipment, it will cause a stain that is difficult or impossible to remove. Therefore, it is recommended (i) to avoid spilling methylene blue, (ii) thoroughly wash and dry all laboratory equipment and glassware immediately after use, and (iii) make sure methylene blue bottles are closed tightly after use. The methylene blue dye test (MBT) is used to determine the cation exchange capacity of the solids present in a drilling mud. The methylene blue capacity gives an estimate of the total cation exchange capacity of the solids in the drilling fluid. The methylene blue capacity of a drilling fluid is an indication of the amount of reactive clays (i.e., bentonite or drilled solids) present as determined by the methylene blue test. Only the reactive portions of the clays present are involved in the test. Materials such as barite, carbonates, and evaporites do not affect the results of the test, since these materials do not adsorb methylene blue. The methylene blue capacity and the cation exchange capacity are not necessarily the same. It is normally somewhat less than the actual cation exchange capacity. Methylene blue solution is added to a sample of drilling fluid which has been treated with hydrogen peroxide and acidified until saturation is noted by the formation of a “dye halo” around a drop of solids placed on filter paper. Drilling fluids frequently contain substances in addition to reactive clays that also absorb methylene blue dye. Pretreatment with

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hydrogen peroxide removes these effects from organic materials such as lignosulfonates, lignites, cellulosic polymers, and polyacrylates. The methylene blue capacity is measured by Eq. (2.35) as: Methylene Blue Capacity ¼

Methylene Blue in ml Drilling Fluid or mud sample in ml

(2.35)

The methylene blue capacity may also be reported as pounds per barrel of equivalent bentonite, based on bentonite with a cation exchange capacity using Eq. (2.35) and which is by Eq. (2.36) and Eq. (2.37). Bentonite equivalent;

Bentonite equivalent;

lbm ¼ 5  Methylene Blue Capacity bbl

(2.36)

kg lbm ¼ 2:85  Bentonite equivalent in m3 bbl

(2.37)

Fann Instrument Company offers a complete Methylene Blue Test Kit containing all reagents, glassware, and hardware required to perform the methylene blue test according the API recommended practice. All items are neatly packaged in a rugged stainless steel carrying case. They also offer the replacement parts and reagents including methylene blue solutions in varying container sizes. 2.3.7.15 Electrical properties Mud resistivity is one of the most important electrical properties of the mud. (i) Mud Resistivity: is the resistance to flow of electrical current through mud system. The resistivity is measured in ohm-m (U mÞ. Drilling mud is influenced by the dissolved salts (in ppm or gpg) and the insoluble solid material contained in the water portion. The resistivity of mud is inversely proportional to the dissolved salt concentration, i.e., the greater the concentration of dissolved salts, the lower the resistivity of the solution. Therefore, fresh-water muds usually have high resistivity and salt-water muds have low resistivity. Unlike metals, the resistivity of a solution decreases as temperature increases. It is necessary to measure resistivity because the mud, mud cake, mud filtrate resistivity exert a strong effect on the electric logs taken in that mud. The mud resistivity varies greatly from the actual resistivity values due to the various factors encountered in the actual operation. A system for measuring resistivity of the formation is attached at the lower end of a casing string while drilling operations continue. The drilling assembly includes all the necessary equipment (explained in Chapter 2), where the motor and bit are electrically isolated from the casing string. Formation resistivity measuring device is provided in the assembly. Data transmission mechanism is provided for encoding the resistivity data and transmitting it through the drilling fluid to the surface location of the wellbore. Fig. 2.36 shows the analog and digital resistivity meters. These testing equipment are the Baroid and Fann Resistivity Meters. The specific gravities of typical drilling fluid solids are illustrated in Table 2.19. The density changes in temperature and pressure will change the volumes of the components. Literature shows that mud compositions including solids might have a significant change due to the changes of pressure and temperature.

114 TABLE 2.19

2. State-of-the-art of drilling

Specific gravity of solids in drilling fluids.

Drilling fluid component

Specific gravity

Drilling fluid component

Specific gravity

Drilling fluid component

Specific gravity

Attapulgite

2.89

Cuttings

z2.6

Limestone

2.8

Barite

4.2

Galena

7.50

Sand

2.63

Bentonite

2.6

Hematite

5.05

Siderite

3.08

Calcium chloride

1.96

Ilmenite

4.6

Sodium chloride

2.16

2.3.8 Current development on drilling fluids In its endeavor to provide a sustainable flow of hydrocarbon energy, the petroleum industry has been recognized by the general public as an industry that has negatively impacted the environment as a result of using either harmful materials or risky practices. This leads the industry to continuously invest in R&D to develop environmentally friendly technologies and products. For any new technology or product, the current R&D trend is toward the development of sustainable practices and expertise. As we know, drilling fluids are necessary for drilling oil and gas wells. Unfortunately drilling fluids have become increasingly more complex in order to satisfy the various operational demands and challenges. The materials used in the process to improve the quality and functions of the drilling fluids contaminate the subsurface and underground systems, landfills, and surrounding environment. Due to the increasing environmental awareness and pressure from environmental agencies throughout the world, it is very important to look back to the drilling fluid technology to reassess its progress while it tries to make forward steps to improve the petroleum industry’s position as an environment friendly industry. Recently, Apaleke et al. (2012a,b) conducted an extensive review on the current development of mud system. 2.3.8.1 Formulation of WBM The water-based drilling fluids, which simulate the performance of the oil-based drilling fluids are commonly referred to as high performance water-based muds (HPWBM) (Marin et al., 2009). The main benefits of HPWBM include the reduction of environmental impacts, and lower down costs associated with cuttings and fluids disposal. Reid et al. (1992) evaluated a novel inhibitive water-based fluid for tertiary shale that was formulated primarily from tetra-potassium pyrophosphate. They observed that the formulation was considerably more inhibitive than other mud systems (even approached the level of that observed with OBM). Kjosnes et al. (2003) designed a water-based mud from a mixture of potassium chloride and polymers such as polyanionic celluloses/xathan gum. When this mud is applied, they observed that the formulation resulted in improved hole cleaning optimization and hole stability. Al-Ansari et al. (2005) formulated an HPWBM comprising of partially hydrolyzed polyacrylamide (PHPA, for cutting encapsulation) and polyamide derivatives (for suppressing the hydration and dispersion tendency of reactive clays). They concluded that

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the formulation which had been used successfully to drill several wells in the Arabian Gulf is an environmentally friendly and performance driven alternative to OBM. Young and Ramses (2006) developed a unique water-based fluid by blending a hydration suppressant, a dispersion suppressant, a rheology controller (xathan gum), a filtration controller, and an accretion suppressant. The formulation according to them delivered an invert emulsion-like drilling performance. Ramirez et al. (2007) developed an aluminum-based HPWBM that was used successfully to drill an exploratory well in the Magellan Strait, Argentina. The well was drilled through notoriously troublesome shales to total depth without the wellbore stability problems associated with more conventional water based muds. Gas kicks were controlled with no fluid solubility problems and the fluid exhibited excellent properties even when pressure parameters escalated higher than planned, requiring a higher mud density and high degree of temperature stability. The operator's expectations were met in this very difficult well including minimization of bit balling, near gauge hole and improved ROP in conjunction with optimum hydraulics. They claimed that not only did the HPWBM replace the oil-based mud, it is also environmentally friendly. Marin et al. (2009) formulated an HPWBM from a blend of salt and polymers at different mud weights. They recommended the inclusion of sized calcium carbonate if drilling through high permeability sands. 2.3.8.2 Formulation of OBM OBM is the most effective drilling fluid when drilling or exploring for oil in frontier areas where extremely high geothermal gradient is a major challenge. However, recently, there are concerns about the restrictions of its use globally due to stiffer government regulations, very high cost of disposal, and treatment of cuttings from the use of OBM. Nowadays, costs of formulation have received more attention from researchers than improved formulation (Oakley et al., 1991). As early as in 1950, it was reported that muds containing air blown asphalt were the most effective due in part to their superior plastering properties and flexibility of temperature range. Oakley et al. (1991) designed an oil-based mud based on oilsoluble polymers (amidoamines and imidazolines) that would reduce the oil on drill cuttings. Based on results from their laboratory tests, they concluded that oil on cuttings can be reduced by up to 30% on current 50:50 oil-water ratio. Herzhaft et al. (2003) studied the influence of temperature and clays/emulsion microstructure on oil-based mud of low shear rate rheology. They concluded that organophilic clays, in interaction with the emulsion droplets, are responsible for the low shear rate. Chen et al. (2004) formulated an oil-based mud system using VERSA, LLD, BOO, and NOVA (emulsifying and oil-wetting agents) to study the effects of OBM invasion on irreducible water saturation. Their experimental findings show that originally strong water-wet Berea and limestone cores were altered to become intermediate-wet or oil-wet by OBM surfactants thus faulting the assumption of waterwetness by the NMR T2 cut-off model which generally underestimates the value of irreducible water saturation (Swir). They proposed that the magnitude of underestimation depends on the type of OBM surfactants, their concentration in the flushing fluid, and the flushing time. They suggested that the effects of OBM invasion on the NMR misinterpret in the real drilling process when wettabilty alteration occurs. This effect can be minimized by controlling the invasion volume and the concentration of OBM surfactants in the invasion fluid. Cheraghian, G. et al. (2018) introduced the possibility of using nanomaterials as part of the drilling fluid system.

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2.3.8.3 Formulation of gas-based mud Most of the technological improvements seen in the drilling of well with air have come from the mining industry, which is primarily associated with shallow, large bore wells. The oil and gas industry has failed to make the same technological advancement in air drilling as compared to wells drilled with liquid or mud systems (Mellot, 2008). However, the following are some of the current trends in the use of air for drilling: Foam: This involves the injection of a dilute solution of a suitable foaming into the air stream. Foam effectively removed cuttings at lower annular velocities that was possible with air alone (Mellot, 2008). Aerate Mud: This involves the direct injection of compressed air from a 3-stage compressor through the stand pipe into the mud system. A special check valve is placed in the drillstring one joint below the Kelly to prevent the problem of mud spray when making connections (Kenneth et al., 2007). Gel Foam and Stiff Foam: Basically, this is the use of a slurry prepared consisting of (by weight) 98% water; 0.3% soda ash; 3.5% bentonite; 0.17% guar gum; and 1% volume of a suitable commercially available foaming agent. In recent formulations, guar gum has been substituted by other polymers and bentonite by other clays (Crews, 1964). 2.3.8.4 Development of environment-friendly mud system The current trend in drilling fluid development is to come up with novel environmentally friendly drilling fluids that will rival the OBM in terms of low toxicity level, performance, efficiency, and cost. Several researchers have come up with formulations of drilling fluid with minimal but not zero environmental impact. E Van Dort et al. (1996) formulated an improved water-based drilling fluid based on soluble silicates capable of drilling through heaving shale which is environmentally friendly. However, this is not recommended because silicate has the potential to damage the formation. Skalle et al. (1999) suggested the use of micro-sized spherical mono-sized polymer beads as a blend to WBM to improve lubrication. Thaemlitz et al. (1999) formulated a new environmentally friendly and chromium-free drilling fluid for HPHT drilling based on only two polymeric components. Brady et al. (1998) came up with a polyglycol enriched water-based drilling fluid that will provide high level of shale inhibition in fresh water and low salinity water-based drilling fluid. However, this formulation has a defect. There must have the presence of electrolytes in the mud system to get the optimum performance. They discussed the technical performance and environmental benefits of a new class of glycol inhibitors, specifically designed to provide high levels of shale inhibition in freshwater and low-salinity water-base drilling fluids. Waste disposal implications are considered and inhibitive properties are compared with other available fluids. Nicora et al. (1998) developed a new generation dispersant for environmentally friendly drilling fluids based on zirconium citrate. The zirconium citrate is used to improve the rheological stability of conventional water-based fluids at high temperature. However, this formulation has a limitation in that the concentration of zirconium citrate may be depleted in the drilling fluid due to solids absorption. The latest research involves novel methods of altering particle properties. For instance, Alois et al. (2017) studied contact electrification of aerosolized micro particles using a novel technique involving laser velocimetry. This has allowed the simultaneous determination of size and electrical charge of individual

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silica microspheres (in the range 1 e 8 mm). Interestingly the particles interacting with the injector tube have been seen to become electrified with a relatively narrow range of surface charge concentration of around Q/4pr2 ~ 100 e-/mm2 (~ 0.02 mC/m2) for all particle sizes. In the future this technique is intended also to be applied to particle-particle induced contact electrification and its material dependence. To avoid some of the above mentioned problems, Sharm et al. (2010) developed an environmentally friendly drilling fluid, which can effectively replace oil-based drilling fluid by using ecofriendly polymers derived from tamarind gum and tragacanth gum. Tamarind gum is derived from tamarin seed while tragacanth gum is from astragalus gummifier. This formulation is also cheaper and has less damaging effect on the formation. Hector et al. (2002) developed a formulation with a void toxicity based on a potassium-silicate system. The advantage of this formulation apart from being environmentally friendly is that cuttings from the use of this drilling fluid can be used as fertilizers. Warren et al. (2003) developed a formulation based on water-soluble polymer amphoteric cellulose ether (ACE) which is cheaper, low in solids content, environmentally friendly, but with some potential to damage the formation. Davidson et al. (2004) developed a drilling fluid system that is environmentally friendly. It also removes free hydrogen sulphide which may be encountered while drilling based on ferrous iron complex with a carbohydrate derivative (ferrous gluconate). Ramirez et al. (2005) formulated a biodegradable drilling fluid. It maintains hole stability and also enables drilling through sensitive shale possible based on aluminum hydroxide complex (AHC). The mud was made up of clay, shale stabilisers, an ROP enhancer, and scaling agents. It was noted that the mud formulation prevented hole problem and was tolerant with carbon dioxide and hydrate contaminations. It was also noted that the mud formulation prevented bit balling and improved the rate of bit penetration. This formulation contains some blown asphalt and hence possesses some environmental problems. Dosunmu et al. (2010) developed an oil-based drilling fluid based on vegetable oil derived from palm oil and ground nut oil. The fluid did not only satisfy environmental standards, it also improved crop growth when discharged into farm lands. All these efforts of the researchers brought the drilling fluid technology in a responsible position which is environmentally friendly and cost effective up to some extent. However, these formulations do not have zero environmental impact yet. Therefore, the question is: Is the development of a zero impact environmentally friendly drilling fluid possible? 2.3.8.5 Application of nanotechnology Nano-silica, nano-graphene, and other nano-based materials have been proposed for use as alternative mud additives. A nanomaterial-based mud system is defined as that mud containing at least one additive with particle size in the range of 1e100 nm (Amanullah et al., 2009). It is based on the number of nano-sized additives in the mud system. Mud systems can be classified as simple nano-mud system or advanced nano-mud system. Nanomaterials in mud systems are expected to reduce the total solids and/or chemical content of such mud systems and hence reduce the overall cost of mud system development. Cheraghian et al. (2018) studied the feasibility of using two types of nanoparticle additives in water-based drilling fluid. Clay/SiO2 nanocomposite was synthesized (by effective hydrothermal method) and successfully characterised. A series of experiments are performed to evaluate the effect of SiO2 and clay nanoparticles on the rheological and filtration properties of water-base drilling

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fluids. The experiments are conducted at different concentrations of Clay/SiO2 and SiO2 nanoparticles, and also at a range of temperatures. The results showed that the addition of clay and SiO2 nanoparticles improved the rheological and fluid loss properties. It was also noticed that the nanoparticles provide thermal stability to the drilling fluid. The experimental results suggest that the Clay/SiO2 nanoparticles have a more significant impact on the rheological and fluid loss properties of the drilling fluid comparing to SiO2 nanoparticles, particularly at higher temperatures. 2.3.8.6 Application of biomass Cellulose is the main component of the cell walls of trees and plants. Its purest form is called nano crystalline cellulose (NCC) which is treated as strengthening and stiffening material. Currently, a number of oil companies in Canada have teamed up to conduct research into the possibility of using NCC as an alternative drilling fluid additive toward the development of a sustainable mud system.

2.3.9 Future trend on drilling fluids There are challenges to further improve the mud engineering technology. Those challenges need to be fulfilled by the researchers in future. Recently, Apaleke et al. (2012a,b) conducted an extensive review on the future development of drilling fluid as challenges and trend of the mud engineering. 2.3.9.1 Cost analysis Cost of developing environment-friendly OBM for field application is a future challenge because of its higher cost. The future of research in drilling fluid development should be directed toward the formulation of an environmentally friendly drilling fluid with zero impact on the environment. This is pertinent because incidents of environmental pollution due to the discharge of oil-based drilling wastes into the environment keep increasing, while the regulations set by the government agencies and NGOs of different countries are restricting the use of OBMs. Therefore, the use of OBM is becoming stricter. To solve the stringent pollutant contents from mud system, Ammnullah (2010) proposed the use of waste vegetable oil in the formulation of environment friendly OBM. Ogunrinde and Dosunmu (2010) suggested the use of palm oil. A major multinational oil company for offshore drilling operations had used highly de-aromatized aliphatic solvents to formulate low toxicity mud system. These formulations though have zero environmental impact, are very expensive. As a result, bringing their cost of formulation down so that overall cost of drilling becomes cheaper is definitely a challenge. 2.3.9.2 Development of environment friendly mud additives Hazardous effects of additives such as defoamers, descalers, thinners, viscosifiers, lubricants, stabilizers, surfactants, and corrosion inhibitors on marine and human life had been reported. Effect ranges from minor physiological changes to reduced fertility and higher mortality rates. For example, Wills (2000) reported that ferro-chrome lignosulfonate, a common drilling mud additive used as a thinner and deflocculant, has effects on survival and physiological responses of fish eggs and fry; the filtration control additive CMC (carboxymethyl-cellulose) can cause death in fish fry at high concentrations (1,000-2,000mg/l) and

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physiological changes at 12-50 mg/l, whereas at the low concentrations (1-20mg/l) used in standard chronic tests it has no observed effects. Another example of the use of toxic additive in OBM formulation is the dumping of 896 tons of drilling mud containing SOLTEX on the coast of Great Britain. When questioned, both the company and the government body overseeing the industry provided only the trade name of the active additive in the dumped drilling mud as SOLTEX with no reference to the fact that SOLTEX contained potentially toxic heavy metals as revealed by Greenpeace in a publication in 1995. Information provided in the product data sheet of some additives has revealed that these additives can cause cancer in an individual if he/she is exposed to these additives. It is well recognized that toxic additives are the high performers. So, how will they be replaced? Answering this question obviously is one of the future challenges researchers will have to contend with. 2.3.9.3 Sustainability Drilling fluid’s position is still in a challenging environment if its status is analyzed based on sustainability though there is a tremendous advancement in this technology. It is due to the complex formulation of the mud system which is needed to meet the different desired properties for smooth functioning while drilling. In addition, mud system’s sustainability has to do with two issues: (1) Ensuring the continuous availability of the base oils used in the formulation of environment-friendly mud systems, (2) Executing a complete drilling program in a safe and environment friendly manner. These two issues put forward a challenging environment to the researchers. Recently, Hossain (2011) proposed a sustainable drilling pathway. He also proposed a diagnostic test procedure toward greening of the drilling fluid system. Follow up of his proposed protocol is a real challenge for the petroleum industry because of cost, need for technological advancement, and availability of the innovative sustainable chemical additives. The initialization should come considering the environment-friendly base oils with zero toxicity instead of conventional base oil. The sources are from plants where there is no use of toxic or unhealthy materials during the complete process. These objectives provide researchers in a challenging situation for achieving their goals. Ensuring resources availability in a timely manner is also a big challenge. 2.3.9.4 Development of mud and/or additives for HTHP applications At extreme high temperature and high pressure (HTHP) conditions, mud systems formulated with macro- and micro-based materials (chemicals and polymers) become drastically altered (Amanullah et al., 2009). This is due to the breakage or association of polymer chains and branches by vibration, Brownian motion, and thermal stress causing drastic reduction in gelling and viscous properties. To solve this problem, nanos with excellent thermal stability and with extreme pressure consistency should be developed.

2.4 Drilling hydraulics In drilling engineering, drilling hydraulics plays a vital role in assuring safe and effective operations. Hydraulic energy affects (i) drill bit, (ii) frictional pressure drops through the drillpipe and various surface equipment, (iii) efficient cleaning ability of the drilling system, and (iv) proper utilization of mud pump horsepower are some of the features necessary to optimize

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for efficient, safe, and cost-effective drilling operations. If not optimized, a hydraulic system can (i) slow down the ROP, (ii) fail to properly clean the hole of drill cuttings, (iii) cause lost circulation, and finally (iv) lead to blowout of the well. To understand and properly design the hydraulic system, it is important to discuss hydrostatic pressure, types of fluid flow, criteria for type of flow, and types of fluids commonly used in the various operations at the drilling industry. Such discussion involves the type of fluids; pressure losses in the surface connections, pipes, annulus, and the bit; jet bit nozzle size selection; surge pressures due to vertical pipe movement; optimization of bit hydraulics; and carrying capacity of drilling fluid.

2.4.1 Types of fluids There are different types of fluids. Almost all the fluids follow the following categories: (i) Newtonian fluid (ii) Non-Newtonian Fluid 2.4.1.1 Newtonian Fluid Normally Newtonian fluids are those liquids where low molecular weight substances exist. Examples include water, light crude oil, organic and inorganic liquids, gases, solutions of low molecular weight inorganic salts, molten metals, and salts which exhibit Newtonian flow behavior. A Newtonian fluid can be defined as “the shear stress is directly proportional to shear rate at a constant temperature and pressure.” The constant proportionality is known as dynamic viscosity of fluid. The shear stress and the rate of deformation are normally expressed by the Newton’s law of viscosity which can be written mathematically as: s ¼ md

dux ¼ m ðgÞ dy

(2.38)

Here: s ¼ shear stress, Pa md ¼ dynamic viscosity, Pa-s dux dy or g ¼ the velocity gradient perpendicular to the direction of shear, or equivalently the strain rate, s1 In field unit, viscosity is expressed in centipoises (1 P ¼ 100 centipoise) and the field unit of share stress is in lbf/100 ft2. Fig. 2.24 shows the linear variation of shear stress with shear rate. The slope of the line gives the viscosity of the fluid. Eq. (2.38) is called Newtonian fluid model. The linear relationship between shear stress and shear rate as illustrated by Eq. (2.38) is valid only if the fluid moves in confined layers or laminae. A fluid that flows in this type of arrangement is said to be laminar flow. This phenomenon is true only at relatively low rates of share. The pipe flow and other types of flow will be discussed in the next section of this chapter. 2.4.1.2 Non-Newtonian fluid A non-Newtonian fluid is a fluid whose flow behavior or properties is not same as Newtonian fluid, i.e., fundamentally the rate of shear is not proportional to the corresponding stress and cannot be described by a single constant value of viscosity. Most of the drilling

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fluids fall under non-Newtonian fluid due to their complex characteristics in behavior. Some other examples can be illustrated as foams, suspensions, polymer solutions, and melts. NonNewtonian fluids can be classified as (i) shear-thickening, (ii) shear-thinning, (iii) time-dependent (i.e., thixotropic, and rheopectic), visco-plastic, and visco-elastic fluids. In addition to these types of fluids, non-Newtonian fluids can also be categorized as (i) Bingham plastic and (ii) power-law fluids. A shear-thickening fluid is defined as a fluid in which apparent viscosity increases with the increase of shear strain rate. It is also termed as dilatant. A shear-thinning fluid is the opposite of shear-thickening fluid where apparent viscosity decreases with the increase of the rate of shear strain which is also called as pseudoplastic fluid. Examples of this type of fluids are drilling fluids and cement slurries in general. There are also fluids that are time-dependent; a fluid is called thixotropic if the apparent viscosity decreases with time after the shear rate is increased to a new constant value. On the other hand, if the apparent viscosity increases with time after the shear rate is increased to a new constant value is called as rheopectic fluid. Again, drilling fluids and cement slurries are generally thixotropic. A fluid that exhibits a viscoelastic property, i.e., a blend of viscous fluid behavior and of elastic solidlike behavior, is called visco-elastic fluid. Viscoelasticity is the property of materials that exhibit both viscous and elastic characteristics when undergoing deformation, such as honey. Fig. 2.25 shows the typical flow curves (i.e., rheograms) on a Cartesian coordinates for the above mentioned different categories of fluid behavior. 2.4.1.3 Different rheological models for non-Newtonian fluids For non-Newtonian fluids, there are some rheological models that describe the relationship between shear stress and shear rate when a fluid flows through a circular section or an annulus. The rheological models are generally used to approximate the fluid behavior. Among the various rheological models, this chapter considers the most widely used models and one newly developed model by the first author of this book. The models are: (i) Bingham plastic model, (ii) power-law model, (iii) shear-thinning fluid model, and (iv) Herschel-Bulkley model. The other model for Newtonian model is already discussed in the above section. (i) Bingham Plastic Models: Bingham plastic fluids can be defined as the fluids that have a linear stress-strain relationship and which require a finite yield stress before they start to flow. The linear plot of stress-strain relationship does not pass through the origin which intersects to a point of stress line. Examples are clay suspensions, toothpaste, mayonnaise, chocolate, and mustard. Fig. 2.26. depicts the relationship between the shear rate and shear stress. Bingham plastic models are used to approximate the pseudoplastic behavior (i.e., decrease of apparent viscosity with increasing shear rate) of drilling fluids and cement slurries. It is defined in terms of the shear stress and shear rate which are given by the following mathematical models: s ¼ m p g þ sy

if s > sy

(2.39a)

s ¼ m p g  sy

ifs < sy

(2.39b)

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FIGURE 2.27 Shear rate versus shear stress relationship for power-law fluid: (A) pseudoplastic power-law fluid, and (B) dilatants power-law fluid.

Here: sy ¼ a minimum shear stress that needs to initiate fluid flow, Pa mp ¼ Bingham plastic viscosity, Pa-s The definition of Bingham plastic fluid says that there will not be any flow until there is a certain minimum shear stress applied to the fluid which is called a yield point stress (sy ). It may also predict a nonphysical yield point. Once the yield point has been exceeded, changes in shear stress are proportional to changes in shear rate. The of the curve (Fig. 2.27) or   slope the constant proportionality is called the plastic viscosity mp . The plastic viscosity depends on pressure and temperature. The above two Bingham plastic models are valid for only laminar flow. These models work well for higher shear rates. However, the models give a significant error at low shear rates. (ii) Power-Law Models: Power-law fluid can be defined as a fluid in which the shear stress at any point is proportional to the rate of shear at that point with some power on the shear rate. The rheological equation for the power law model can be given as: s ¼ Kgnp

(2.40)

Here: x K ¼ flow consistency index, Pa: sn g ¼ du dy ¼ shear rate or velocity gradient perpendicular 1 the plan of shear, s np ¼ power-law exponent or flow behavior index, dimensionless The apparent viscosity as a function of shear rate can be written as: sapp ¼ Kgnp 1

(2.41)

Power-law fluids can be further classified into three different types of fluids based on np : (i) pseudoplastic fluid for np < 1, (ii) Newtonian fluid for np ¼ 1, and (iii) Dilatant fluid for

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np > 1. The power-law models are also known as Ostwald-de Waele model. Eqs. (2.29) and (2.30) are useful because they are simple and require only two parameters for characterizing fluid behavior. These models are also used to approximate the pseudoplastic behavior of drilling fluids and cement slurries. However, these models can only approximate the behavior of a real non-Newtonian fluid. Fig. 2.41 shows the graphical representation of the model Eqs. (2.40) and (2.41). In the power-law model, K is a measure of the thickness of the fluid which is analogous to apparent viscosity of the fluid. The larger the K value, the thicker the fluid is. The value of n indicates the degree of non-Newtonian behavior of the fluid which plays a vital role. For example, if n is less than one, the power-law forecasts the effective viscosity which decreases with the increase of shear rate indefinitely. It is noted that in Eq. (2.30), 0 < np < 1 will yield ðdsapp =dgÞh0 which indicates that shear-thinning behavior of fluids are characterized by a value of np < 1. Lots of polymer melts and solutions have the value of n in the range of 0.3e0.7 based on the concentration, molecular weight of the polymer, and some other properties. In addition, smaller values of power-law index (np z0:1  0:15) are encountered with fine particle suspensions like kaolin-in-water, bentonite-in-water, etc. Naturally, the smaller the value of np , more shear-thinning the material is. Although, Eqs. (2.40) or (2.41) offers the simplest approximation of shear-thinning behavior, it predicts neither the upper nor the lower Newtonian plateaus in the limits of g/0 or g/N. In addition, a fluid needs infinite viscosity at rest and zero viscosity while the shear rate approaches infinity. However, a real fluid has a minimum and maximum effective viscosity which depends on the physical chemistry at the molecular level. Thus, the power law models (Eqs. 2.40 and 2.41) are only a good representation of the fluid behavior within the range of shear rates to which the coefficients are fitted. The shortcoming of powerlaw model is that it underestimates the shear stresses at medium and low shear rate ranges. In literature, there are a number of other models that better explain the entire flow behavior of shear-dependent fluids such as shear-thinning fluid. The following section presents some models as an example. (iii) Shear-thinning fluid models: The majority of complex fluids used in oil field applications are non-Newtonian polymeric solutions demonstrating shear-thinning (pseudoplastic) behavior in solution. The two main polymers used in the oil industry for hydrocarbon recovery are synthetic polyacrylamide (in its partially hydrolyzed form, HPAM) and Xanthan biopolymer gum. Bulk properties measurement of polymeric solutions is a standard and reliable experimental procedure. Therefore, researcher’s efforts have been made to extend the laws of motion for purely Newtonian fluids (Darcy’s law) to rheologically complex ones using easily measurable properties such as the shear rate/viscosity behavior. A bundle of parallel capillary tubes approach has been used to measure the macroscopic and microscopic properties of porous media. This approach leads to the definition of an average radius which is dependent on macroscopic properties of the medium such as porosity, absolute permeability, and some measure of tortuosity. The available mathematical models (such as power law, Carreau, or Cross models) to describe the fluid rheology have been developed to define viscosity and apparent shear rate from the use of the Darcy velocity. Experimental results show that the shape of the apparent viscosity curve is

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similar to that of bulk shear rate. Most of experimental works had been performed by Xanthan biopolymers whose experimental results are available in the literature where they tried to find the shape factor, aSF . For the porous media, Chauveteru’s form of the definition of porous media wall shear strain rate or in-situ shear rate is aSF ux g_ pm ¼ pffiffiffiffiffiffiffi kf

(2.42)

Here: ux ¼ Fluid velocity in porous media in the direction of x axis, m=saSF ¼ Shape factor which is medium-dependent g_ pm ¼ Apparent shear rate within the porous medium, s1 k ¼ Reservoir permeability, m2 f ¼ porosity of fluid media, m3 =m3 In the context of polymer flooding (part of enhanced oil recovery schemes), in-situ rheology depends on polymer type and concentration, residual oil saturation, core material, and other related properties which are addressed in the available literature. A brief discussion has been outlined by Lopez (2004). The existence of a slip phenomenon in the Newtonian region at ultra-low flow rates is confirmed and the degree of shift (the aSF factor) in the nonNewtonian region is quantified. It is shown that the adoption of rigorous and reproducible core flood procedures is required to yield unambiguous data on in-situ polymer viscosity and polymer retention in real systems. Some researchers pointed out that Eq. (2.42) has a generic form which depends on polymer type, medium structure, and approach. In this area, there have been developed several constitutive equations in the past that capture the full bulk rheological behavior of pseudoplastic solutions. To model the bulk rheology of the non-Newtonian fluid, Carreau-Yasuda model may be written as: meff ¼ mN þ h

ðm0  mN Þ
a inac 1 þ lg_ pm

(2.43)

Here: a ¼ Parameter in Carreau-Yasuda model, dimensionless nc ¼ Power-law exponent for Carreau-Yasuda model, dimensionless meff ¼ Fluid effective viscosity, Pa  sm0 ¼ Fluid dynamic viscosity at zero shear rate, Pa  smN ¼ Fluid dynamic viscosity at infinite shear rate, Pa  sl ¼ time constant in CarreauYasuda model, s The exact form of the shear stress-shear rate (stress-strain) relationship depends on the nature of the polymeric solution. Therefore, recently, a question is always coming out about the effect of memory on rock/fluids in porous media when predicting oil flow outcomes. Hossain and Islam (2006) have reviewed the existing complex fluid flow models with memory available in literature. None of them has focused the shear thinning fluid models which may couple with fluid memory. Hossain et al. (2007, 2008) have developed a model which represents a more realistic rheological behavior of fluid and media. They have developed a stress-strain relation coupling the macroscopic and microscopic properties with

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memory (see Chapter 3). In that model, they did not consider the polymeric fluid properties in porous media. However, the conventional practice is to consider the Newtonian fluid flow equations as ideal models for making predictions. Even non-Newtonian models focus on what is immediately present and tangible in regard to fluid properties. The bulk macroscopic properties of these solutions, mainly their viscosity/shear rate dependency, are well understood and characterized using established models. Existing theoretical models as well as experimental findings are well established in the literature. Recently, Hossain et al. (2009) attempted to model shear rate and viscosity of polymeric complex fluid as a function of time and other related bulk properties of fluid and media itself where memory has been incorporated to represent macroscopic and microscopic behavior of fluid and media in a more realistic way. They argue that the intangible dimension of time and other fluid and media properties can be coupled to demonstrate the more complex behavior of shear thinning fluids in porous media. Hossain et al. (2009) proposed the following model for apparent shear rate. Zt aSF h v2 p g_ pm ¼ pffiffiffiffiffiffi dx (2.44) ðt  xÞa vxvx kf Gð1  aÞ 0

Here: p ¼ pressure of the system, N=m2 t ¼ time, sa ¼ fractional order of differentiation, dimensionless h ¼ ratio of the pseudopermeability of the medium with memory to fluid viscosity, m3 s1 þ a =kgx ¼ a dummy variable for time, i.e., real part in the plane of the integral, s Eq. (2.44) provides the effects of the polymer fluid and formation properties in one dimensional fluid flow with memory and this model may be extended to a more general case of three-dimensional flow for a heterogeneous and anisotropic formation. It should be mentioned here that the first part of Eq. (2.44) is the apparent core properties; second part is the effects of fluid memory with time and the pressure gradient. The second part is in a form of convolution integral that shows the effect of the fluid memory during the flow  process. This integral has two variable functions of ðt  xÞa and v2 p vxvx where the first one is a continuous changing function and second one is a fixed function. This means that  ðt  xÞa is an overlapping function on the other function v2 p vxvx in the mathematical point of view. These two functions depend on space, time, pressure, and a dummy variable. To analyze the memory effect in the shear-thinning fluid viscosity, Hossain et al. (2009) proposed the following model for effective viscosity. meff ¼ mN þ 2 6 6 61 þ 4

0 Blha B SF B pffiffiffiffiffiffi @ kf

m0  mN Rt 0

1a 3nac

(2.45)

7 7 C7 A5

a v2 p dxC C vxvx

ðt  xÞ

Gð1  aÞ

The solution of Eqs. (2.43) and (2.45) is shown in Fig. 2.28 which shows the variation of viscosity versus shear rate of the Hossain et al. (Eq. 2.45) for different a values to compare

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FIGURE 2.28

Comparison of Hossain et al. viscosity model with Carreau-Yasuda model.

FIGURE 2.29

Shear rate versus shear stress relationship for Herschel-Bulkley fluid.

the Carreau-Yasuda model (Eq. 2.32) in a log-log plotting. All the data generated by solving these two models are overlapped with each other except the range of data variation. For the same conditions and input data, the proposed model gives more information than CarreauYasuda model. The proposed model provides a wider range of data in both zero shear and infinite shear region. The existence of Carreau-Yasuda model is only in power-law region if

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we compare it with proposed model. It is also noted that all a values data lie in the transition and power-law region which are very difficult to capture and explain. If a increases, the data range extends to reach the other two regions, zero shear and infinite shear. Therefore it may be concluded that the proposed model is more appealing and illustrative in defining the rheological properties of the shear-thinning fluid flow in porous media. (iv) Herschel-Bulkley model: The Herschel-Bulkley model is a combination of the Bingham plastic and the power law models. It is also known as the yield power-law model. This model considers the yield point shear stress which is a shortcoming of the power-law model. Fig. 2.29 shows the stress-strain relationship for the HerschelBulkley model. Mathematically, this model is defined as:

s ¼ Kgn þ sy

(2.46)

In Eq. (2.46), if sy ¼ 0, the Herschel-Bulkley model is reduced to the power-law model. On the other hand if n ¼ 1, the model reduces to the Bingham plastic model. It is noted that sometime nonlinear regression is needed for solving the resultant mathematical expressions which are not readily solved analytically. This model is preferable compared to power law or Bingham models because it gives more accurate rheological behavior when adequate experimental data are available. The yield stress is normally taken as the 3 rpm reading, with the n and K values then calculated from the 600 or 300 rpm values or graphically. Some drilling fluids fall under the Herschel-Bulkley fluid model. It requires a certain minimum stress to initiate flow.

2.4.2 Flow regimes When a fluid is forced to flow inside a pipe (e.g., drillpipe, drill collar), there are different geometrical configurations or flow regimes prevail. Flow regime can be defined as a range of stream flows that have similar bed forms, flow resistance, and means of transporting sediment. While drilling fluids flow in a well, the fluid behavior may differ because the regime depends on the fluid properties, length and the size of the conduit, and the flow rate. The flow regime also depends on the configuration of the inlet. In general, flow regimes can be classified as (i) laminar flow, (ii) transition flow, and (iii) turbulent flow. 2.4.2.1 Laminar flow The most common annular flow regime is laminar which is also known as streamline flow and creates a steady-state flow (Fig. 2.30A). It is sometimes referred to as sheet flow, or layered flow. Laminar flow can be defined as the motion of a fluid where every particle in the fluid follows the same path of its previous particles. It occurs when a fluid flows in parallel layers, with no disruption between the layers. It exists from very low pump rates to the rate at which turbulence begins. At low velocities, the fluid tends to flow in an organized way. There are no cross-flows perpendicular to the direction of flow, nor eddies, or spins of fluids. In laminar flow, the motion of the particles of fluid is very orderly with all particles moving in straight lines parallel to the pipe walls. The fluid moves fastest in the center of the

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(A) Max Velocity V=0 Laminar Flow

Characteristics of laminar flow

(B)

(C)

r

r

v

pipe flow

FIGURE 2.30

annular flow

Characteristics and the velocity profiles for laminar flow.

conduit and slowest at the walls (Fig. 2.30). It is also true for pipe and annular flow too (Fig. 2.30B). This indicates that center layers usually move at rates greater than the layers near the wellbore or pipe. The major characteristics of this flow regime are: (i) flow pattern is linear, i.e., no radial flow, (ii) fluid velocity at the center of the pipe is maximum and velocity at wall is zero, (iii) it produces minimal hole erosion, (iv) as the flow velocity increases, the flow type changes from laminar to turbulent. Laminar flow can be characterized by Reynolds number ðNRe Þ. If Reynolds number is less than 2100 ði.e. NRe < 2100Þ, the flow is treated as laminar flow. 2.4.2.2 Turbulent flow Turbulent flow or turbulence is a flow regime characterized by chaotic nature of the fluid property changes. Turbulent flows are always highly irregular and chaotic but not all chaotic flows are turbulent (Fig. 2.31). Turbulence occurs when increased velocities between the layers create shear strengths exceeding the ability of the mud to remain in laminar flow. The layered structure becomes chaotic and turbulent (Fig. 2.31CeD). Turbulent flows are unsteady by definition. A constant source of energy supply is necessary to continue turbulent flow. Otherwise, turbulence disperses rapidly as the kinetic energy is converted into internal energy by viscous shear stress. It causes eddies formation of many different length scales. Turbulent flow can be characterized by Reynolds number ðNRe Þ. Flows with high Reynolds numbers generally become turbulent. For pipe flow, if the Reynolds number is greater than 4000 ði.e. NRe > 4000Þ, the flow is treated as turbulent flow.However, we often assume that fluid flow is turbulent if NRe > 2100. Turbulence takes place usually in the drillstring and seldom around the drill collars. Much published literature suggests that annular turbulent flow increases hole erosion problems. In summary, the basic characteristics of turbulent flow can be written as: (i) flow pattern is random (flow in all directions), (ii) tends to produce hole erosion, (iii) results in higher pressure losses (takes more energy), (iv) provides excellent hole cleaning but forms eddies

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FIGURE 2.31 Characteristics of turbulent flow: (A) laminar flow, (B) transition between laminar and turbulent flow and (CeE) turbulent flow.

in wall of the drillstring. A comparison between laminar and turbulent flow is shown in Table 2.20. Reynolds number: Reynolds observed that when circulating Newtonian fluids through pipes the onset of turbulence was dependant on the variables such as (i) pipe diameter (d), (ii) density of fluid , (iii) viscosity of fluid (m), (iv) average flow velocity (v). He also found that the onset of turbulence occurred when the above combination of these variables exceeded a value of 2100. Reynold’s observation was very significant because it means that the onset of turbulence can be predicted for pipes of any size, and fluids of any density or viscosity, flowing at any rate through the pipe. This grouping of variables is generally termed a dimensionless group which is known as the Reynolds number. Therefore, the onset of turbulence in pipe flow is characterized by the dimensionless group as: NRe ¼ Here: r ¼ Fluid density, gm/cc v ¼ Avg. fluid velocity, cm/s di ¼ Pipe inner diameter, cm

r vdi m

(2.47)

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TABLE 2.20

A comparison between laminar and turbulent flow.

Flow type

Laminar flow

Turbulent flow

01

Flow is smooth.

Flow pattern is random in both time and space.

02

Flow is essentially organized and layered.

Flow is essentially random and unpredictable and seconds the well-defined laminar flow conditions.

03

Velocity increase toward the middle.

Uniform at its final stage.

04

Only longitudinal velocity.

Longitudinal and transverse velocities.

05

Same uniform velocity.

Final velocity is uniform.

06

Plug flow is a special case of laminar flow (flat at center).

No Plug flow.

07

Plug flow occurs at low velocity and high viscosity of fluid.

No plug flow.

08

Laminar shear resistance.

Laminar and turbulent shear resistance.

09

md ¼ Dynamic viscosity of fluid, cp q ¼ Circulating volume, cc/s In field units, Reynolds number can be written as: NRe ¼

928 r vdi m

(2.48)

Here: r ¼ Fluid density, lbm/gal q v ¼ Avg. fluid velocity, ft/s ¼ 2:448 d ¼ Pipe inner diameter, in. d2i i md ¼ Dynamic viscosity of fluid, cp q ¼ Circulating volume, gal/min Reynolds found that as he increased the fluid velocity in the tube, the flow pattern changed from laminar to turbulent at a Reynolds number of 2100. However, later investigators have shown that under certain conditions (i.e., non-Newtonian fluids and very smooth conduits),

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FIGURE 2.32

131

Characteristics of transition flow.

laminar flow can exist at very much higher Reynolds numbers. For Reynolds numbers of between 2000 and 4000 the flow is actually in a transition region between laminar flow and fully developed turbulent flow (Fig. 2.31B). 2.4.2.3 Transitional flow In the case of pipe flow, when the fluid velocity increases the layers of fluid start to become a little unstable. This type of flow is called transitional flow (Fig. 2.8). Therefore, this flow can be defined as a mixture of laminar and turbulent flow where turbulence occurs in the center of the pipe, and laminar flow near the edges. If the flow rate continues to increase further, the flow turns down to turbulent flow. In such a situation, it is often difficult to estimate the flow rate at which turbulence may take place. A range of Reynolds number can lead to find out the transition zone. If 2100 < NRe < 4000, flow is in transition, and is neither laminar nor turbulent, sometimes called mixed flow. However, during any design, it is chosen as turbulent for being in the safe side (Fig. 2.32). It is sometime easy to characterize the transition zone by critical fluid velocity. It is used to define the velocity at which the flow regime changes from laminar to turbulent. This variable is the most important since all other parameters in the Reynolds number equation (Eqs. 2.35 or 2.36) are considered constant. Since no single Reynolds number defines the transitional zone, it follows that arrangement of critical velocities may be necessary to determine the flow regime. Based on critical velocity criteria, flow regimes can be characterized by critical velocity ðVc Þ, and actual velocity ðVac Þ as: (i) if Vc > Vac , flow is laminar, (ii) if Vc < Vac , flow is turbulent, and (iii) if Vc zVac , flow is transitional. The critical velocity can be determined for the Bingham plastic model as: qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 1:08mp þ 1:08 m2p þ 12:34 rm d2i sy VcB ¼ (2.49) rm di Here: VcB ¼ Critical velocity for the Bingham plastic model, ft/s rm ¼ Mud density, ppg

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di ¼ Pipe inner diameter, in. The critical flow rate can be determined for the Bingham plastic model as: QcB ¼ 2:448  VcB  d2i

(2.50)

Here: QcB ¼ Critical flow rate for the Bingham plastic model, gpm

2.4.3 Hydrostatic pressure calculation The hydrostatic pressure of the drilling fluid is an important feature in maintaining control of a well. The understanding of this feature is also needed to prevent blowouts. Hydrostatic pressure is defined as the static pressure of a column of fluid. Most of the fluid in the drillstring is mainly drilling mud. However, it can contain air, natural gas, foam, mist, or aerated mud. Therefore, this section is divided into three subsections, (i) liquid column, (ii) gas column, and (iii) complex fluid column. 2.4.3.1 Liquid columns The subsurface well pressures are normally determined easily for static well conditions. The liquid-based systems such as mud are considered in this section. The hydrostatic pressure of a mud column is a function of the mud weight and the true vertical depth of the well. It is very important to pay attention to the well depth because it should be confirmed that the measured depth, or total depth, is not used erroneously. Fig. 2.33 shows the freebody diagram from which variation of pressure with depth can be derived mathematically. The downward force acting on the fluid element can be calculated as: Fdown ¼ pA

(2.51)

FIGURE 2.33 Fluid column where distribution of forces act on the fluid element. The upward force acting on the fluid element can be calculated as.

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Here: Fdown ¼ Downward force on the fluid element applied by the fluid column above, lbf p ¼ Pressure on the fluid element, psig A ¼ Inner cross-sectional area of the fluid column, in2.   dp DLtvd A Fup ¼ p þ (2.52) dLtvd Here: Fup ¼ Upward force on the fluid element applied by the below fluid column, lbf Ltvd ¼ Total vertical depth, ft DLtvd ¼ Differential total vertical depth, ft dp dLtvd ¼ Pressure gradient with respect to total vertical depth, psig/ft Finally the weight of the fluid element itself is exerting a downward force which can be calculated as: Fself ¼ Wsp ADLtvd

(2.53)

Here: Fself ¼ Fluid element’s self-weightacting as a downward force, lbf Wsp ¼ Specific weight of fluid, lbf in2  ft If we consider that fluid is at rest, there will not be any shear forces acting on the fluid element and thus all forces acting on the fluid element must be in equilibrium, i.e., Fdown þ ðFup Þ þ Wsp ADLtvd ¼ 0

(2.54)

  dp pA  p þ DLtvd A þ Wsp ADLtvd ¼ 0 dLtvd

(2.55)

dp ADLtvd þ Wsp ADLtvd ¼ 0 dLtvd

(2.56)

pA  pA 

dp ¼ Wsp dLtvd

(2.57)

For drilling operations, normally we deal with a liquid such as drilling mud or salt water where fluid compressibility is negligible, and specific weight can be considered constant with depth. With these approximations, Eq. (2.57) can be integrated for an incompressible fluid which gives the following final form: p ¼ Wsp Ltvd þ po Here: po ¼ Surface pressure at Ltvd ¼ 0 which is also the constant of the integral.

(2.58)

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2. State-of-the-art of drilling

In general, the static surface pressure, po is zero unless the blowout preventer of the well is closed and the well is trying to flow. The specific weight of the liquid in field unit can be written as: Wsp ¼ 0:052 rm

(2.59)

Here:  Wsp ¼ Specific weight of fluid, lbf in2  ft Therefore, Eq. (2.58) can be written in field unit as: p ¼ 0:052 rm Ltvd þ po

(2.60)

Since mud weights and well depths are often measured with different units, the constant of Eq. (2.59) will vary. Common forms of the hydrostatic pressure equation are as follows: p ¼ 0:052  ðmud weight; lbm = galÞ  ðdepth; ftÞ; where p is in psia

(2.61a)

  p ¼ 0:00695  mud weight; lbm = ft3  ðdepth; ftÞ; where p is in psia

(2.61b)

  p ¼ 9:81  mud weight; g = cm3  ðdepth; mÞ; where p is in kPa

(2.61c)

If a column of fluid contains several mud weights, the total hydrostatic pressure is the sum of the individual fluid column or section: X pt ¼ Cri Li (2.62) Here: pt ¼ Total hydrostatic pressure C ¼ Conversion constant ri ¼ Mud weight for the section of interest Li ¼ Length for the section of interest (which is part of Ltvd ) Eq. (2.62) leads to the concept of Equivalent Mud Weight (EMW) which is frequently used in drilling operation. Drilling operations often involve several fluid densities, pressures resulting from fluid circulation, and perhaps applied surface pressure during kick control operations. It is useful in practical applications to discuss this complex pressure and fluid density arrangement on a common basis. The approach most widely used is to convert all pressures to an “EMW” that would provide the same pressures in a static system with no surface pressure. The EMW concept is a convenient way to compare the pressures at any depth. For example, a 12,000-ft well has two mud weights. It contains 6000 ft of 10.0 lbm/gal mud and 6000 ft of 12.0 lbm/gal mud. Now, the equivalent mud weight at 12,000 ft is 11.0 lbm/gal, even though the well does not contain any real 11.0 lbm/gal mud. Mathematically, EMW in lbm/gal (i.e., ppg) can be calculated as: EMW ¼

pt 0:052 Ltvd

(2.63a)

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135

If the well is deviated a deg from the vertical, the EMW is given by: EMW ¼

pt 0:052 Dm cos a

(2.63b)

Here: Dm ¼ Measured depth, ft. Another term commonly used to describe the equivalent mud weight concept is equivalent circulating density (ECD). ECD results from the addition of the equivalent mud weight, due to the annular pressure loss, to the original mud weight. The ECD usually considers the hydrostatic pressures and the friction pressure resulting from fluid movement. For example, a 13.0 lbm/gal mud may act as if it is 13.4 lbm/gal mud (due to the friction pressure) while it is pumped. Some drilling engineers may refer to the ECD in this case as 0.4 lbm/gal. Typical ranges for the ECD additive factor are 0.1e0.5 lbm/gal. Mathematically, ECD in ppg can be determined as: Dpan ECD ¼ rom þ (2.64a) 0:052 Ltvd Here: rom ¼ Original mud density, ppg Dpan ¼ Annular pressure loss, psi In deviated wells, vertical depth is used. In such a case, Eq. (2.64a) can be modified for multiple sections as: Pnw i¼1 Dpani Pnw ECD ¼ rom þ (2.64b) 0:052 i¼1 Ltvdi Here: nw ¼ number of wellbore sections 2.4.3.2 Gas columns In many cases of drilling and completion operations, gas presence exists at least in a portion of well. Sometime gas is injected to the well from the surface or gas may enter the well from a subsurface formation. It is very important and complicated to calculate the pressure variation of a static gas column because the density of gas changes with pressure. The gas behavior can be described using real gas equation defined by pa V ¼ ZnRT Here: pa ¼ Absolute pressure V ¼ Gas volume Z ¼ Universal gas constant m n ¼ mole of gas ¼ M m ¼ mass of gas

(2.65)

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2. State-of-the-art of drilling

M ¼ Gas molecular weight R ¼ Universal gas constant T ¼ Absolute temperature Gas density can be expressed as a function of pressure using Eq. (2.65) which can be written as r¼

m Mpa ¼ V ZRT

(2.66)

Eq. (2.66) can be expressed in field unit for mud as rm ¼

Mpa 80:3 ZT

(2.67)

Here: pa ¼ Absolute pressure, psia M ¼ Gas molecular weight, fraction T ¼ Absolute temperature, o R For any long gas column, variation of as gas density with depth can be written in terms of pressure gradient using Eq. (2.40) in Eq. (2.32) and then applying the product to Eq. (2.45) yields dp ¼ 0:052

Mpa dLtvd 80:3 ZT

(2.68)

If the gas deviation factor, Z is constant, Eq. (2.68) can be rearranged as integrate both sides as Zpa

1 M dp ¼ p 1; 544 ZT

p0

ZLtvd dLtvd

(2.69)

L0

The final form of Eq. (2.69) gives pa ¼ p0 e

MðLtvd L0 Þ 1;544 ZT

(2.70)

2.4.4 Fluid flow through pipes In rotary drilling operation, the hydraulic system consists of stand pipe, rotary hose, swivel, kelly, drillpipe, drill collar, drill bit, and the annulus. The mud pump discharges the drilling fluid which passes through the surface lines and hydraulic system. The mud begins to travel downward through the drillpipe and drill collars and is expelled through the nozzles of the bit and return up to the surface through the annulus. Since the mud enters the drillstring and leaves the annulus at the same level the only pressure required is to overcome the frictional losses in the system. When drilling fluid circulates, pressure drop

2.4 Drilling hydraulics

137

takes place due to friction between the fluid and the surface in contact. The pressure that forces the drilling fluid to circulate through the hydraulic system is supplied by the mud pump. The mud pump pressure is partly used up in overcoming the friction losses of the hydraulic system including surface facilities. The remaining pump pressure is consumed as drill bit nozzle pressure loss, where the high nozzle speed is needed to remove cuttings from the bit and its surroundings. Therefore, the total discharge pressure at the pump is defined as: DPP ¼ DPsp þ DPdP þ DPdc þ DPbn þ DPac þ DPap

(2.71)

Here: DPP ¼ pump discharge pressure, psi DPsp ¼ pressure loss in surface piping, stand pipe and mud hose, psi DPdp ¼ pressure loss inside drillpipe, psi DPdc ¼ pressure loss inside drill collar, psi DPbn ¼ pressure loss across bit nozzle, psi DPac ¼ pressure loss in annulus in the drill collars, psi DPap ¼ pressure loss in annulus in the drillpipe, psi Fluid flow through pipes is considered as either laminar or turbulent. Calculation of pressure drop for pipe flow requires a knowledge of which flow relates to the specific case, since different equations apply for each situation based on flow type. In such case, definition of Reynolds number (Eqs. 2.20 and 2.21) are important and they are the determinant criteria for pressure drop calculation. There are established equations in literature. The detail explanation can be found in any basic fluid dynamics textbook. There are some equations that can be explained here. The pressure drop in laminar flow is given by the Hagan-Poiseuille law which is given in field unit as: DPLf ¼

mLv 1500d2i

(2.72)

Here: DPLf ¼ Laminar flow pressure drop, psi L ¼ Length of the pipe, ft For turbulent flow, Fanning’s equation can be applied as DPtf ¼

frLv2 25:8di

Here: DPtf ¼ Turbulent flow pressure drop, psi f ¼ Fanning friction factor The friction factor f of Eq. (2.73) can be obtained using a typical f versus Re graph.

(2.73)

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2. State-of-the-art of drilling

2.4.5 Fluid flow through drill bits A tricone bit has three nozzles. Dp ¼

1 r v2 2 m n

(2.74)

Here: Dp ¼ pressure drop or loss at any section, psi rm ¼ mud density in ppg vn ¼ mud velocity at the nozzle, ft/s sffiffiffiffiffiffiffiffiffiffi Dpbit vn ¼ 33:36 rm

(2.75)

Here: Dpbit ¼ pressure drop at the bit, psi Nozzle area can be calculated as: An ¼ 0:3208

q vn

(2.76)

Here: q ¼ mud flow rate, gpm An ¼ total nozzle area at the bit, in2. For tri-cone bit, there are three nozzles with equal sizes, therefore p An ¼ 3 A ¼ 3 d2n 4 Here: dn ¼ equivalent average diameter of individual nozzle at the bit, in. rffiffiffiffiffiffiffiffi 4An dn ¼ 32 3p

(2.77)

(2.78)

2.4.6 Pressure loss calculation of the rig system In the rig system, the total pressure loss includes surface and connections pressure losses, pipe pressure losses (i.e., drillstring: drillpipe, drill collar), annular pressure losses, and pressure drop across the bit (Fig. 2.34). The total system pressure losses of the rig system can be calculated by the following equation which is similar to Eq. (2.71): Prig ¼ Psp þ PdP þ Pdc þ Pbn þ Pach þ Paccas þ Padph þ Padpcas

(2.79)

2.4 Drilling hydraulics

FIGURE 2.34

139

Schematic drawing of the circulating system.

Here: Prig ¼ total pressure loss in the rig system, psi Psp ¼ pressure loss in surface piping, stand pipe and mud hose, psi Pdp ¼ pressure loss inside drillpipe, psi Pdc ¼ pressure loss inside drill collar, psi Pbn ¼ pressure loss across bit nozzle, psi Pac-h ¼ pressure loss in annulus and the drill collars inside hole, psi Pac-cas ¼ pressure loss in annulus and the drill collars inside casing, psi Padp-h ¼ pressure loss around the drill pipe inside hole, psi Padp-cas ¼ pressure loss around the drill pipe inside casing, psi 2.4.6.1 Pipe flow The following equations are used to determine pressure loss while Bingham model is used: The average velocity: v ¼

24:5 q d2i

Here: v ¼ avg. fluid velocity, ft/min q ¼ mud pump rate, gpm di ¼ pipe inner diameter, in. Again, the critical velocity can be calculated using imperial units as: qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 97mp i þ 97 m2p i þ 8:2 rm d2i sy i VcB i ¼ rm di

(2.80)

(2.81)

140

2. State-of-the-art of drilling

Here: VcB i ¼ critical velocity for the Bingham plastic model in imperial unit, ft/min. rm ¼ Mud density, lbgalm (ppg) di ¼ Pipe inner diameter, in. lb sy i ¼ Yield pointing imperial unit, 100 f ft2 mp i ¼ Plastic viscosity in imperial unit, cp If the flow is laminar (i.e., v < VcB i ), the pressure drop can be calculated as:

mp i v L Pdp ¼ (2.82) sy i þ 300D 5di Here: L ¼ length of the drillpipe, ft. If the flow is turbulent (i.e., v > VcB i ), the pressure drop at the drillpipe can be calculated as: Pdp ¼

1:8 0:2 8:91  105 r0:8 m q mp i L

d4:8 i

(2.83)

2.4.6.2 Annular flow The following equations are used to determine pressure loss while Bingham model is used: The average velocity: v ¼

24:5 q d2h  d2dpo

(2.84)

Here: dh ¼ Hole diameter, in. ddpo ¼ Outside diameter of drillpipe, in. Again, the critical velocity can be calculated using imperial units as: qffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi 97mp i þ 97 m2p i þ 6:2 rm d2e sy i VcB i ¼ rm de

(2.85)

Here: de ¼ Annular distance, in ¼ dh  ddpo or. dh  ddco ddco ¼ Outside diameter of drill collar, in. If the flow is laminar (i.e., v < VcB i ), the pressure drop at the annulus can be calculated as: Pan ¼

L mp i v L sy i þ 60; 000D2e 200De

(2.86)

If the flow is turbulent (i.e., v > VcB i ), the pressure drop at the annulus (drillpipe) can be calculated as: Pdp ¼

1:8 0:2 8:91  105 r0:8 m q mp i L 3

ðdh  ddpo Þ ðdh þ ddpo Þ

1:8

(2.87)

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141

Eq. (2.87) can be used for drill collar pressure loss with the change of drillpipe diameter ðddpo Þ by drill collar outside diameter (ddco Þ. 2.4.6.3 Bit flow The pressure drop across the bit nozzle can be calculated using the following equation which is similar to Eq. (4.52): Pbn ¼ Pstandpipe  ðPdP þ Pdc þ þ Pachole þ Paccas þ Padphole þ Padpcas Þ

(2.88)

Section 4.6 discusses the nozzle velocity, nozzle area, and nozzle size. However the pressure loss across the bit is calculated as: Pb ¼

8:311  105 rm q2 C2d A2n

(2.89)

Here: Pb ¼ pressure drop or loss at drill bit, psi rm ¼ mud density in ppg Cd ¼ discharge coefficient which is usually 0.95 The pressure drop across the bit can also be calculated with a 0.95 discharge coefficient as: Pb ¼

rm q 2 10858 A2n

(2.90)

The pressure drop across the bit is calculated with a nozzle velocity as: Pb ¼

rm v2n 1120

(2.91)

Bit hydraulic horsepower (BHHP) can be calculated as: HPb ¼

q Pb 1714

(2.92)

Here: HPb ¼ drill bit hydraulic horsepower, hp Now, bit hydraulic horsepower per square inch of the bit can be calculated as: HPb HPb HPsi ¼ p ¼ 1:273 2 2 db d 4 b Here: HPsi ¼ bit hydraulic horsepower per square inch of the bit, hp/in2. db ¼ diameter of the drill bit, in.

(2.93)

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2. State-of-the-art of drilling

Bit hydraulic power per square inch of the hole drilled can also be calculated as: HPsi

h

HPb HPb ¼ p ¼ 1:273 2 dh d2 4 h

(2.94)

Here: HPsi h ¼ bit hydraulic horsepower per square inch of the hole drilled, hp/in2. dh ¼ diameter of the hole, in.

2.4.7 Current development on drilling hydraulics 2.4.7.1 Drilling hydraulics optimization Drilling hydraulic optimization with conventional drilling fluid is a well-known practice which has been widely practiced in the oil industry. Drilling hydraulics is mainly discussing the pressure needed during drilling to improve drilling and provide sufficient cutting removal capacity and decreasing pressure losses in the circulating system. There are lots of empirical correlations to optimize hydraulics. For example, Fulletron charts, Amoco curves, the use of optimization theory to maximize some arbitrary functions such as maximum bit hydraulic horsepower or jet impact force are among them. This section discusses the current development in hydraulic optimization using down-hole motors and its improvement in overall drilling optimization. It also covers the improvement in the underbalance drilling (UBD) optimization using aerated fluids. Critical characteristics of many of today’s wells, on the other hand, have made it advantageous and even necessary to rely on computer technology to execute the bit hydraulics optimization process. Swanson et al. (1994) are among the first ones who advocated this approach, especially when considering a large number of parameters. Reduction in the number of parameters can simplify computer algorithms and increase chances of converging on a solution, particularly when multiple, narrow boundary conditions are involved. However, unnecessary predefinition of key independent variables can lead to less-than-optimal results. Swanson et al. (1994) stated that drilling hydraulics optimization involves manipulation of several independent variables. One can obtain maximum/ minimum for one or more dependent variables within boundaries imposed by the cost, safety, and physical properties of the analyzed system. Table 2.21 shows a summary of the variables and constrain parameters that are involved in a typical drilling operation. TABLE 2.21

Variables and constrained parameters involved in a typical drilling operation.

Variables

Restriction

Drilling rate

Pump capacity

Drilling Fluid rheology

Drilling cost

Drillstring geometry

Minimum cuttings transport velocity

Bit nozzle size

Wellbore stability

Drilling fluid flow rate

Wellbore geometry

2.4 Drilling hydraulics

143

In addition, accurate quantification of system losses (we already discussed in the previous sections) enhances the validity of calculated equivalent circulating density (ECD) and other drilling parameters and indicators. Determination of pressure drop at the bit is one of the major concerns for establishing proper hydraulic design. Theoretically, most of the hydraulic power should be utilized by the bit. This hydraulic power will then be helpful in hole cleaning and removal of cuttings out of the well. Optimization of this power will be very critical in the directional and horizontal well when cleaning is common and costly problem. Even, this will be most critical particularly in case of extended reach drilling where larger and longer wellbores are drilled. So, lots of studies were carried out to develop a good procedure in cutting transport. Studies found out that turbulent flow regime performed better at high angles. So a drilling fluid with a well-designed fluid rheology should be pumped in the well with high velocity to improve cutting transport and avoid accumulation of cutting in the horizontal and deviated section of the well. Field measurements have revealed that the pressure drop over a slim borehole can also depend significantly on the rotation speed of the drillpipe. Studies explain the influence of drillpipe rotation on the axial frictional pressure drop for the simplest cases such as laminar flow, Newtonian fluid. For laminar flow inertial forces caused by rotation and eccentricity of the drillpipe give rise to the axial pressure drop. 2.4.7.2 Down-hole motor technology In the last decades, use of down-hole motors has increased to meet challenges such as speedup drilling of vertical wells, optimized drilling of directional and horizontal wells, and in particular, extended reach drilling of deep and ultradeep water wells. Determination of proper jet nozzle size is important because a significant increase in rate of penetration (ROP) can be achieved through proper choice of nozzle sizes. For true optimization of jet bit hydraulics, an accurate down-hole motor model must be incorporated including configuration, dimension, weight on bit. So the motor horse power required must be taken as a separate because the pressure drop across the motor is a function of configuration of the motor (number of lobes) and weight on bit applied. Experimental studies showed that ROP increases with a decrease in the number of lobes of the motor under the same weight on bit. At high weight on bit, all motor types gave similar results except the two-lobe motor which resulted in less ROP as compared to other. This is mainly due to the higher WOB used in hard formation which needs strong motor to be used in such environment. In addition, ROP increases with the increase of WOB for the same motor configuration. Fig. 2.15 shows the above relationship as each motor configuration has the optimum operating condition that gives better results. Studies showed that for the soft formations, the best motor configuration is two loops which can result in a higher ROP, but in case of hard or motions which we need to apply more weight on bit, motors with more than 4 loops will be optimum motors. Fig. 2.35 shows a simple schematic of two loops that is used in soft formations. Based on that, best motor configuration that can give better ROP in soft formations is double-lobes motor as shown in Fig. 2.36. Studies also suggested that analysis of optimum flow rate with the down-hole motor gives a more realistic estimation of the optimum flow rate. Also sizing of the bit nozzles is dependent on the configuration of the motor in use.

144

2. State-of-the-art of drilling

FIGURE 2.35

ROP versus WOB for different motor.

FIGURE 2.36

Motor cross-section.

2.4.7.3 Drilling hydraulics for the aerated “foam” fluids Compared to conventional drilling fluids, relatively little is known about the hydraulic and rheological properties of foamed fluids. Nowadays, foam has been used in various fields such as drilling fluids. A typical use of foam fluids is in Extended Reach Drilling (ERD) where Equivalent Circulating Density (ECD) can be reduced with these types of fluids. Other useful applications are in the Underbalanced Drilling (UBD).Foam can be formed by mixing a gas phase (air or similar) with a liquid phase which is either water (stable foam) or aqueous polymer solution (stiff foam) containing 1%e2% by volume foaming agent. The major advantage of foam is its flexibility in controlling the mud’s effective density which has a direct relation with the bottom-hole pressure. Field experiences have shown that the performance of aerated fluids is difficult to predict. There are factors that have a significant effect on the hydraulics of

2.4 Drilling hydraulics

145

the aerated fluids such as type and percentage of gas and liquid forming the foam, foam quality, optimum foam flow velocity, slippage effect, etc. There are different hydraulic models that are used generally to model the drilling hydraulics for the aerated drilling fluids: Blauer et al. Model (1972): it predicts friction losses in laminar, transitional, and turbulent regimes for foam flow assuming that the foam behaves is like a Bingham plastic type of fluid, and can be expressed as below: "  4 # pD3 sw gc 4 sy 1 sy Q¼ þ 1 (2.95) 3 sw 3 sw 32 mp Here D ¼ pipe diameter, L gc ¼ gravitational constant, L/t2 Q ¼ flow rate, L3/t sw ¼ shear stress at tubing wall, m/Lt2 sy ¼ shear stress at y-direction, m/Lt2 mp ¼ plastic viscosity, m/Lt Sanghani model (1982): it is similar to Blauer et al. model. However, the difference is that Sanghani assumed the foam behaves as a pseudoplastic fluid. His model is as below:  n DPf 4K 8ð3n þ 1ÞQ ¼ (2.96) D pnD3 DL Here n ¼ flow-behavior index, dimensionless K ¼ consistency index of power law model, dimensionless DPf 2 DL ¼ Pressure loss due to friction per unit length, (m/Lt )/L Reidenbach et al. model (1986): this model is the empirical correlation for calculating rheological properties of N2 and CO2 foam. The model is based on laminar flow with viscosity dependent on foam quality, yield point, base fluid consistency index, and flow behavior index; and it is developed as below:  1  n0 1 8v 8v þ k0 (2.97) ma ¼ s0YP d d Here ma ¼ apparent viscosity, m/Lt s0YP ¼ geometry dependent yield stress, m/Lt2 v ¼ foam velocity, L/t d ¼ pipe diameter, L K0 ¼ geometry dependent consistency index, dimensionless n0 ¼ geometry dependent flow behavior index, dimensionless Valco and Economides’ model (1992): this model is proposed by a new constitutive equation for non-Newtonian compressible fluids and the ratio of the liquid density to the foam density. It also states that if volume-equalized shear stress is plotted against volumeequalized shear rate, points obtained at different qualities and different geometries lie on

146

2. State-of-the-art of drilling

one curve in isothermal conditions. So, using this principle, frictional pressure losses during isothermal, steady state flow can be estimated using below equation: 2 3 dp 1 4ð2ff b2 c2  Dg Þp3 þ 4ff abc2 p2 þ 2ff a2 c2 p5 ¼  dx D bp3 þ ap2 þ abc2 p þ a2 p2

(2.98)

Here ff ¼ friction factor, dimensionless a ¼ constant coefficient, L2/t2 b ¼ constant coefficient, L3/m c ¼ constant coefficient, m/(t.L2) D ¼ pipe diameter, L g ¼ gravitational constant, L/t2 p ¼ pressure, m/(Lt2) Gardiner et al. model (1998): this model uses the “Volume Equalization Principle” and assumes the flow is isothermal. In addition, the effect of changing axial velocity on radial flow is negligible. He expressed his model as below:  

1 n dp Rnþ1 εn1 n 2 Q ¼ pR uslip þ  (2.99) 3n þ 1 dx 2k Here Q ¼ flow rate, L3/t R ¼ universal gas constant uslip ¼ slip velocity, L/t ε ¼ specific volume expansion ratio, dimensionless n ¼ flow behavior index, dimensionless k ¼ consistency index, dimensionless After the analysis of many experimental studies, it is concluded that there is no best model out of the above to best predict the pressure losses of the actual operations. Drilling hydraulic optimization of aerated fluids is mainly focused on determining optimum foam flow rate, back pressure, foam quality, and others to have an effective cutting transport. Hydraulic optimization varies from well to well depending on the well trajectory and drillstring used for drilling. 2.4.7.4 Drilling hydraulics of aerated fluids for vertical wells The great advantages of using aerated muds for vertical wells are the elimination of lost circulation and formation damage. So the effective foam drilling practice is the effectiveness of cutting transportation while keeping the circulating bottomhole pressure at a minimum level. One of the models considers the combined effects of the drilling rate, the annular back pressure, foam injection rates on the circulating bottomhole pressure, and efficiency of cuttings transport (Osunde and Kuru, 2008). Foam velocity is used as primary term to control the bottom hole pressure whereas cuttings concentration is used to evaluate the cutting transport efficiency.

2.4 Drilling hydraulics

147

Critical foam velocity is specified as the minimum velocity required to lift and transport the cutting out. Krug and Mitchell (1972) suggested that it should be 1.5 ft/s. Guo et al. (1995) suggested that it is the minimum velocity to give 4% as maximum cuttings concentration. Based on that, optimum foam velocity (OFV) is the velocity which yields minimum bottomhole pressure (BHP) while keeping the maximum cuttings concentration in the annulus as less than 4%. Gas Liquid Ratio (GLR) has a significant effect on the BHP and therefore, it requires the optimization of GLR first. In contrast, CLR is a function of annular back pressure (ABP). So, critical GLR is that which gives minimum optimum BHP. Determination of the optimum ABP is an essential first step to achieve minimum BHP. Effect of drilling rate on ABP is negligible, whereas, borehole diameter and well depth have significant effect on the ABP. ABP increases when hole diameter decreases. It also increases when true vertical depth increases. In general, for large hole diameters, the optimum foam rate is always higher than the minimum flow rates required for cuttings transport. Although the hydraulic optimization can be achieved by using these higher injection rates, the overall economics of the well may set a limit on the volumetric flow rates. 2.4.7.5 Drilling hydraulics of aerated fluids for deviated, horizontal, and ERD wells New critical deposition velocity correlation for foam-cuttings flow is introduced where the model is solved numerically to predict cuttings bed height as a function of the drilling rate, the foam injection rates, the rate of fluid influx from the reservoir, and the borehole geometry. Foam muds is used in UBD to achieve a lot of benefits such as increases productivity by reducing formation damage, increases rate of penetration, eliminates loss of circulation, improved formation evaluation while drilling, and reduced stimulation requirements. For deviated and horizontal wells, a two-layer model is developed to study factors affecting cuttings transport with foam as shown schematically in Fig. 2.37 (Skelland and A.H.P, 1967). The model is also stated that foam with cuttings is creating a uniform homogeneous property in an arbitrary cross-sectional area. The foam velocity must be higher than the critical deposition velocity to convey cutting in suspension. Another model (Crowe, 1998) stated that a cutting bed is normally formed when annular flow rate cannot prevent cutting particles from depositing. As the bed grows, the velocity and frictional pressure gradient increase until an equilibrium condition is reached. Therefore, the model considers two different layers (upper layer and stationary bed) and employs mass and momentum conservation equations. The model has the following differential form:  v v  vðAo pÞ 1 ðAo Cs rs us Þ þ Ao Cs rs u2s ¼ Cs þ Ao bv ðuf þ us Þ  Cs fs rs u2s So vt vx vx 2 Here Ao ¼ cross-sectional area of the upper layer in the horizontal model, m2 Cs ¼ volumetric concentration of the dispersed phase rs ¼ density of the dispersed phase, kg/m3 us ¼ velocity of the dispersed phase, m/s uf ¼ foam velocity, m/s p ¼ pressure, Pa bv ¼ coefficient accounting for drag force, kg/(s.m3)

(2.100)

148

2. State-of-the-art of drilling

fs ¼ fanning friction coefficient of the dispersed phase, dimensionless So ¼ source term of oil, kg/(s.m3) Ford et al. (1990) reported that larger cuttings are more difficult to transport at all angles of inclination if using low-viscosity fluids. Wilson (1978) stated that when cuttings decrease in size to 0.5 mm in a near horizontal condition, it is much more difficult to move the small particles. Tomren (1979) stated that an increase in the hole angle greatly decreases the cuttings transport efficiency and reported that 40 inclination is the most difficult angle for hole cleaning. 2.4.7.6 Drilling hydraulics for coiled tubing drilling Due to the fact that coiled tubing is curved in shape, friction losses of flow of the drilling fluids are greater than that of a straight pipe because of existence of secondary flow. This flow is caused by the effect of centrifugal forces in curved-flow geometry. Numerous efforts have been given to provide a complete set of friction-factor correlations for both Newtonian and non-Newtonian fluids under laminar and turbulent flow regimes (Zhou et al., 2005). These correlations took into account the pipe roughness and its effects on the pressure losses. Ito (1969): For Newtonian Fluids, one of the reported correlations in literature is the Ito correlation for laminar flow which can be written as: fCL ¼ 0:1033 ND0:5e fSL

"

1:729 1þ N De

0:5

1:315  0:5 N De

#3 (2.101)

Here fCL ¼ the friction factors of laminar flow in curved pipes, dimensionless fSL ¼ the friction factors of laminar flow in straight pipes, dimensionless NDe ¼ Dean number, (NRe (a/R)) NRe ¼ Reynolds number, dimensionless In Eq. (2.101), the Dean number is defined as the product of the Reynold number and the square root of the curvature ratio (a/R). This correlation was obtained numerically using the approach of boundary-layer approximation. Ito (1959) has also developed a correlation for turbulent flow which can be written as fCT


a 2 0:25 1
a 0:5 ¼ 0:029 þ 0:304 NRe 4 R R

(2.102)

Here fCL ¼ the friction factors of turbulent flow in curved pipes
2 Eq. (2.92) is valid for 0.034 Qr Þ Qmin  Q  Qmax In his doctoral work, Sun (2013) further developed the HERL model. He considered the rated power of drilling pump as a new constraint condition. The HERL model based on new constraint condition is also introduced. However, these studies only consider the effects of rated pressure of drilling pump and rated power of drilling pump on the HERL model; the allowable range of drilling fluid flow rate, an important hydraulic parameter range, was not taken into consideration.

348

4. Advances in horizontal well drilling

where Lh is the horizontal-section limit, m; Lh1 is the horizontal-section limit based on rated pump pressure, m; Lh2 is the horizontal-section limit based on rated pump power, m; pr is the rated pressure of drilling pump, MPa; Pr is the rated power of drilling pump, kW; Dpg is surface pipeline pressure drop, MPa; Dpb is bit pressure drop, MPa; DpstvDpstv is the drillstring pressure losses of vertical section, MPa; Dpstd is the drill string pressure losses of deviated sections, MPa; Dpav is the annular pressure losses of vertical section, MPa; Dpads is annular pressure losses of small-inclination section, MPa; Dpadl is annular pressure losses of large-inclination section, MPa; (Dp/DL)sth is drillstring pressure loss gradients in horizontal section, MPa/m; (Dp/DL)ah is annular pressure loss gradients in horizontal section, MPa/m. According to the relationship between the allowable range of drilling fluid flow rate, Qmin  Q  Qmax and the rated flow rate of drilling pump Qr, Eq. (4.47) can be divided into the following three cases, including Qmin  Qr  Qmax, Qmin < Qmax < Qr, and Qr < Qmin < Qmax Qr < Qmin < Qmax. They are expressed in Eqs. (4.48)e(4.50). Case I: Qmin  Qr  Qmax; þ Dpstd Þ  ðDpay þ Dpads þ Dpadl Þ 8 L ¼ pr  Dpg  Dpb  ðDp sty



; h1 > Dp Dp > > > þ > > DL sth DL ah > > > > > > ðQmin  Q  Qr Þ < Lh ¼ pr >  Dpg  Dpb  ðDpsty þ Dpstd Þ  ðDpay þ Dpads þ Dpadl Þ > > Q > >



L ¼ > h2 > > Dp Dp > > þ > > DL sth DL ah :

(4.48)

ðQr  Q  Qmax Þ where Qrr is rated flow rate of drilling pump, L/s. Case II: Qmin < Qmax < Qr ; Lh ¼ Lh1 ¼

pr  Dpg  Dpb  ðDpsty þ Dpstd Þ  ðDpay þ Dpads þ Dpadl Þ



; ðQmin  Q Dp Dp þ DL sth DL ah

(4.49)

Case III: Qr < Qmin < Qmax ; Lh ¼ Lh2

pr  Dpg  Dpb  ðDpsty þ Dpstd Þ  ðDpay þ Dpads þ Dpadl Þ Q



; ¼ Dp Dp þ DL sth DL ah ðQr < Qmin  Q  Qmax Þ

(4.50)

349

4.4 Longer reach horizontal well

4.4.2 Application example For a horizontal ERW, the established HERL model is used to predict the well’s HERL, especially the horizontal-section limit. The specific data of this well is listed in Tables 4.2 and 4.3, and schematic overview of the horizontal ERW is illustrated in Fig. 4.18. Several assumptions are inherent to this analysis. They are: - the fracture pressure in the horizontal section is identical. Without this assumption, the parameter sensitivity analysis becomes spurious due to the shift in the basis of comparisons. - the bearing capacity of drilled formation and hole cleaning are rendered driving function for the allowable range of drilling fluid flow rate. The analysis by Li et al. (2017) pinned the lower limit based on the needs of hole cleaning Qhc to be 29.6 L/s. The lower limit considering the bearing capacity of drilled formation becomes Qmin is 27.1 L/s, and the upper limit of drilling fluid flow rate Qmax is 39 L/s. Therefore, the allowable range of drilling fluid flow rate ranges from 29.6 to 38.5 L/s. Operating conditions are given in Tables 4.2 and 4.3. Depending on the relationship between allowable range of drilling fluid flow rate and the rated flow rate of drilling pump Qr, the HERL model belongs to Case I, as described by Eq. (4.48). Effects of drilling fluid flow rate on the horizontal-section limit based on rated pump pressure Lh1 and the horizontal-section limit based on rated pump power Lh2 are shown in Fig. 4.19A, which is also the schematic overview of the situation of Qmin  Qr  Qmax (Case I). Li et al. (2017) performed the analysis in order to determine the effects of different parameters on the HERL especially the horizontal-section limit of horizontal ERW. Furthermore, results simulated by the established model were compared with the results of the previous model that did not consider the allowable range of drilling fluid flow rate. In order to determine the effect of the rate of penetration (ROP), allowable ranges of drilling fluid flow rate under different ROPs (6 m/h, 8 m/h, 10 m/h) were used (See Table 4.4). As shown in Table 4.4, the lower limit of drilling fluid flow rate Qmin gradually increases and the upper limit of drilling fluid flow rate Qmax keeps decreasing as ROP increases. The effects of different ROPs on Lh1 and Lh2 are shown in Fig. 4.19B. As shown in Fig. 4.19B, Lh1 first increases and subsequently decreases with the increase in drilling fluid flow rate, whereas Lh2 keep decreases with the increase in drilling fluid flow rate. Moreover, both Lh1 and Lh2 have a negative correlation with ROP under the condition of identical drilling fluid flow rate, since the TABLE 4.2

Design table for casing.

Casing program

Bit size/mm

Casing outer diameter/mm

Conductor

558.8

476.3

30

Surface casing

444.5

339.7

700

Intermediate casing

311.2

244.5

2407

Open hole

215.9

e

e

From Li et al. (2017).

Casing depth/m

350 TABLE 4.3

4. Advances in horizontal well drilling

List of input data for modeling.

Variables

Value

Unit

Inclination at KOP

0




L

1956.3

m

20.55




90




Build rate Inclination at target bate

/100 m

True vertical depth D

2241

m

Horizontal displacement before the horizontal section

280

m

Drilling fluid density rm

1.35

g/cm3

Cuttings density rs

2.5

g/cm3

Flow behavior index n

0.7365

d

Consistency coefficient K

0.7565

Pa.sn

Fracture pressure equivalent density rf

1.91

g/cm3

Designed horizontal-section length Li

1500

m

Drill pipe outer diameter D1

139.7

mm

Drill pipe rotation speed N

40

rpm

Rate of penetration ROP

10

m/h

Rated pump pressure p

39

MPa

Rated pump power P

1323

kW

annular cuttings and the annular pressure losses increase with the increase in ROP. It can be seen that ROP has no effects on the rated flow rate of drilling pump Qr, and Qr ¼ 34 L/s. In a series of numerical runs, the effects of drillpipe rotation speed on HERL were studied. Results of allowable ranges of drilling fluid flow rate under different drillpipe rotation speeds (10 rpm, 40 rpm, 70 rpm) are listed in Table 4.4. Table 4.4 shows that the lower limit of drilling fluid flow rate Qmin decreases and the upper limit of drilling fluid flow rate Qmax increases with the increase in drillpipe rotation speed N. In other words, the window of drilling fluid flow rate becomes wider. The effects of different drillpipe rotation speeds on Lh1 and Lh2 are shown in Fig. 4.19C. The effects of different rated pump pressures on Lh1 and Lh2 are shown in Fig. 4.20 (Case II). Fig. 4.20 shows that Lh1 first increases, but later decreases with the increase in drilling fluid flow rate, with a clear optimum behavior. On the other hand, Lh2 maintains a monotonous relationship with drilling fluid flow rate. Moreover, the higher pr corresponds to the greater Lh1 when drilling fluid flow rates are the same. However, pr has no effects on Lh2. Effect of rated power of drilling pump on HERL is studied. Initially, allowable ranges of drilling fluid flow rate under different rated pump powers Pr are calculated. Which situation the HERL belongs to and which kind of HERL model needs to be adopted can be determined

4.4 Longer reach horizontal well

FIGURE 4.18

351

Schematic of the drilling schemed modeled by Li et al. (2017).

according to the relationships between these allowable ranges of drilling fluid flow rate and the rated flow rate of the drilling pump Qr. Table 4.4 shows that rated pressure of drilling pump Pr has no effects on hole cleaning and the bearing capacity of drilled formation. The situation of Pr ¼ 1049 kW is focused in this part, which belongs to the situation of Case III, and the horizontal-section limit can be determined by Eq. (6). The effects of rated pressure of drilling pump Pr on Lh1 and Lh2 are shown in Fig. 4.21A. Similarly, Fig. 4.21A shows that Lh1 first increases and subsequently decreases with the increase in drilling fluid flow rate, whereas Lh2 has a consistent negative correlation with drilling fluid flow rate. Moreover, the higher rated pressure of drilling pump Pr means the greater Lh2 with identical drilling fluid flow rate. However, Pr has no effects on Lh1. As shown in Eq. (4.50), the horizontalsection limit Lh depends entirely on Lh2 when Qr < Qmin < Qmax, which is indicated by the yellow dotted area in Fig. 4.21A. Therefore, the maximum horizontal-section limit Lhmax can be obtained at the drilling fluid flow rate Q when Lh2max is achieved rather than the rated flow rate of drilling pump Qr. Fig. 4.20 shows that the horizontal-section limit Lh at Qr is larger than Lhmax when Pr ¼ 1049 kW. Therefore, if the allowable range of drilling fluid

9000

horizontal-section limit based on rated pump pressure (Lh1) horizontal-section limit based on rated pump power (Lh2)

8000 horizontal-section limit (m)

352

(A)

Lh2max

7000

Qmin > > 2pi  ðR1 þ ðj  1ÞÞ  2  rc > > ðj  1Þ  2  rc if 0 < x  > > > n > > < 2pi  ðR1 þ jÞ  2  rc RðxÞ ¼

n > > > > > 2pi  ðR1 þ ðj  1ÞÞ  2  rc 2pi  ðR1 þ ðj  1ÞÞ  2  rc > > > ðj þ 1Þ  2  rc if  2 

> n n > > > : / . (7.27) The parameters which depend on the radius of the drum, and thus functions of the hook position “x,” can be calculated as Eqs. (7.4)e(7.7), where “mpipes” is mass of the pipes on the drill string, “mT” is mass of the top-drive, “mca” is mass of the cable, “mcyl” is mass of the cylinder, “mca0” is mass of the cable at initial time, “mcyl0” is mass of the cylinder at initial time, “mcal” is mass of the cable with length of 1 m, “mdisk” is mass of the disk, “rdisk” is radius of the disk, and “R2” is the inner radius of the cylinder

614

7. Monitoring and global optimization

FIGURE 7.51

Control block diagram.

mca ¼ mca0 þ n  x  mca1 mcyl ¼ mcyl0  n  x  mca1    2 1 1 2 2 Id ¼ mcyl  r þ R2 þ 2  mdisk  rdisk 2 2 mH ¼ mpipes þ mT þ mca mH ¼ mpipes þ mT þ mca

(7.28)

mca ¼ mca0 þ n  x  mca1

(7.29)

mcyl ¼ mcyl0  n  x  mca1

(7.30)

    1 1 Id ¼ mcyl  r2 þ R22 þ 2  mdisk  r2disk 2 2

(7.31)

In Eq. (7.2), which describes the rotational motion of drill string, the variable “u” is the rotational velocity, the variable “I” is the moment of inertia of drill string and BHA, the variable c is the torsional stiffness of the drill string, “sT” is the torque applied by the top-drive, the variable “T” is the torque on bit, and “Du” is the external disturbance effecting on the

7.6 Adaptive control in drilling operations

615

rotational motion. During the drilling operation, the variables, WOB and torque on bit, are calculated as W ¼ 2paxεvu T ¼ pa2εvu

W ¼ 2Paxεv=u

(7.32)

T ¼ Pa2 εv=u

(7.33)

where the constant “a” is the bit radius, the constant “x” is the ratio of the vertical force to the horizontal force between rock and cutter contact surfaces, and the variable “ε” is the rock stiffness. During the tripping, reaming, and back reaming operations, the weight and torque on bit terms equal zero, as there is no rockebit interaction. It is worth mentioning that, during the drilling, the WOB term will be limited, in such a way not exceeding a determined value as will be described in section “WOB controller,” and the torque on bit term will be eliminated as a disturbance from the system. Step 2: Controller design: The controlling process must be performed for all modes of operation, and for each operating mode, an appropriate controller must be designed. During each operating mode, position and/or velocity control must be performed by the controller. The control block diagram of the system is shown in Fig. 7.52. In order to control the velocity of the hook during the operating modes, five control strategies are designed and implemented: cascade PID controller (CPID), active disturbance rejection controller (ADRC), loop shaping controller (LSC), feedback error learning controller (FEL), and sliding mode controller (SMC). The CPID, ADRC, and SMC controllers have been applied in many works and presented in the literature. The design of the LSC and FEL controllers applied on the model is another novelty of this work. The design process of all the controllers is described in detail. Step 3: CPID controller: The CPID controller is mainly exerted to achieve fast rejection of disturbance before it propagates to the other parts of the plant. Fig. 7.52 illustrates the simplest architecture of a cascade control, which involves two inner and outer control loops.

FIGURE 7.52

Structure of cascade PID controller.

616

7. Monitoring and global optimization

The first PID controller in the outer loop is the primary controller that regulates the controlled variable (velocity) by setting the set-point of the inner loop. The second PID controller in the inner loop rejects disturbance (D2D2; acceleration) locally before it propagates to the plant. The tuning of both PID controllers are manually implemented and optimized to achieve the minimum tracking error. Step 4: ADRC controller: The architecture of the ADRC is illustrated in Fig. 7.52. It consists of two main components: the proportionalederivative (PD) controller and the ESO (extended state observer). The designed ESO will eliminate all the uncertain forces effecting on the system. In other words, this controller can successfully track the reference signal while rejecting all the uncertainties and disturbances. Using the equation of vertical motion (Eq. 7.1), the dynamics of the observer can be derived as follows: Step 5: LSC controller: The LSC design method, also known as the frequency responsee based controller design method, conceptually consists of two steps: convert all design specifications to loop gain constraints and find a controller to meet the specifications (Fig. 7.53). Step 6: FEL controller: The combination of a classic controller with an artificial neural network (ANN) is known as FEL as shown in Fig. 7.54. Adaptive type of controller is used to handle the uncertainty due to the various extra annoying forces. Two types of FEL

FIGURE 7.53

FIGURE 7.54

Structure of FEL controller.

Structure of sliding mode controller.

7.6 Adaptive control in drilling operations

617

controllers are constructed and implemented; a PID controller is used (FEL1), and an ADRC controller is used (FEL2), as the classic controller. Step 7: SMC controller: One of the simplest architectures to robust control is the so-called SMC methodology. It is able to eliminate the effect of the model parametric uncertainties and the external disturbances, as described in the following. The architecture of our SMC is illustrated in Fig. 7.54. Based on the design procedure, presented in the mentioned reference,1 an SMC is designed to the vertical motion system. The dynamics of the vertical motion as presented previously is a second-order equation as follows: Step 8: controller optimization: In order to optimize the controller parameters, the vertical speed must meet the step response requirements as rise time less than 0.3 s, settling time less than 1 s, and overshoot less than 1%. The controller variables to be optimized are separately as follows. The current and optimized value of the variables for each controller: CPID; Proportional (P), Integral (I), Derivative (D), Filter Coefficient (N) of the inner loop (i), and outer loop (o); ADRC; Proportional (P), Derivative (D), Filter Coefficient (N), and Observer Bandwidth (u0); LSC; Open-Loop Bandwidth (uc); FEL1; Proportional (P), Derivative (D), and Filter Coefficient (N); FEL2; Proportional (P), Derivative (D), and Filter Coefficient (N); SMC; Positive Constants (l and h). Step 9: Evaluation of the controllers: The evaluation and comparison of the designed controllers is implemented, using the performance measures described by Eqs. 7.28e7.31. The integral square error (ISE), integral absolute error (IAE), integral of time weighted absolute error (ITAE), and root mean square error (RMSE) values are derived from the simulation results and then the performance of the controllers are evaluated. For vertical motion, the error signal is considered as e ¼ urefu, and for rotational motion as e ¼ urefu. Step 10: WOB controller: The optimization process of drilling parameters has direct effects on the cost reduction, which aims to optimize controllable variables during drilling operation such as WOB for obtaining maximum ROP, as the economic factor.51 Determination of optimum WOB is very important in drilling operation as this parameter can be changed during drilling operation. Based on the existing conditions and constraints in the field, during the drilling process the WOB parameter must be limited, in such a way not exceeding the determined value. To constrain the WOB limitation, three control architectures are designed. The first approach constrains the WOB limit by decreasing the vertical speed, the second one by increasing the rotational speed, and the last one combines these two approaches. In other words, it first increases the rotational speed to a certain limit and then decreases the vertical speed, in such a way the WOB limit is not exceeded. So long as the WOB is smaller than the determined value, the vertical and rotational speeds track their reference values, but once it exceeds the determined value, first the rotational speed reference increases, and then if it does not suffice, the vertical speed reference decreases by the WOB increase rate. As the vertical speed or ROP plays an economic role in the drilling process, our priority is increasing of rotational speed, instead of decreasing the ROP.

618

7. Monitoring and global optimization

On the other hand, to provide a constant drilling state at the bit like WOB, and ROP, the autonomous drilling is generally implemented. The four individual modes of control for autonomous drilling are WOB mode, ROP mode, DeltaeP mode, and torque mode. In the WOB mode, the control system controls the vertical speed or ROP to maintain a preset constant WOB, which is the optimum value of it. The optimization methods can be applied to the problem of selecting the best WOB to achieve the minimum cost per foot.45 To design such a controller, two different architectures can be implemented. In the first approach, based on Eq. (7.3), which represents the WOB according to the vertical and rotational speed, we can derive the proper vertical speed reference to give a predetermined value for the WOB, assuming a constant rotational speed. By this approach, it is assumed that the rock stiffness is determined or it can be estimated by a special observer. In the second approach, the proper vertical speed reference can be easily achieved by the production of the measured vertical speed and the difference rate of measured and predetermined WOB.

C H A P T E R

8 Environmental sustainability 8.1 Introduction Petroleum hydrocarbons are considered to be the backbone of the modern economy. The petroleum industry that took off from the golden era of 1930s never ceased to dominate all aspects of our society. Until now, there is no suitable alternative to fossil fuel, and all trends indicate continued dominance of the petroleum industry in the foreseeable future (Islam et al., 2018). Even though petroleum operations have been based on solid scientific excellence and engineering marvels, only recently it has been discovered that many of the practices are not environmentally sustainable. Practically all activities of hydrocarbon operations are accompanied by undesirable discharges of liquid, solid, and gaseous wastes (Khan and Islam, 2007), which have enormous impacts on the environment (Islam et al., 2010; Islam and Khan, 2019; Islam, 2020). Hence, reducing environmental impact is the most pressing issue today, and many environmentalist groups are calling for curtailing petroleum operations altogether. Even though there is no appropriate tool or guideline available in achieving sustainability in this sector, there are numerous studies that criticize the petroleum sector and attempt to curtail petroleum activities (Holdway, 2002). There is clearly a need to develop a new management approach in hydrocarbon operations. The new approach should be environmentally acceptable, economically profitable, and socially responsible. This follows the need to develop a new economic tool to evaluate sustainable technologies. This chapter looks environmental sustainability in petroleum operations. In particular, it focuses on drilling practices and recommends means to make them sustainable.

8.2 Environmental sustainability of petroleum operations The crude oil is truly a nontoxic, natural, and biodegradable product but the way it is refined is responsible for all the problems created by fossil fuel utilization. The refined oil is hard to biodegrade and is toxic to all living objects. Refining crude oil and processing natural gas use large amount of toxic chemicals and catalysts including heavy metals. These heavy metals contaminate the end products and are burnt along with the fuels producing various toxic by-products. The pathways of these toxic chemicals and catalysts show that they severely affect the environment and public health. The use of toxic catalysts creates Drilling Engineering https://doi.org/10.1016/B978-0-12-820193-0.00008-3

619

© 2021 Elsevier Inc. All rights reserved.

620

8. Environmental sustainability

many environmental effects that make irreversible damage to the global ecosystem. A detailed pathway analysis of formation of crude oil and the pathway of refined oil and gas clearly shows that the problem of oil and gas operation lies during synthesis or their refining. For drilling operations, the sustainability can be restored only by avoiding chemicals that are inherently sustainable.

8.2.1 Pathways of crude oil formation Crude oil is a naturally occurring liquid found in formations in the earth consisting of a complex mixture of hydrocarbons consisting of various lengths. It contains mainly four groups of hydrocarbons among which saturated hydrocarbons consist of straight chain of carbon atoms, aromatics consist of ring chains, asphaltene consists of complex polycyclic hydrocarbons with complicated carbon rings, and other compounds mostly are nitrogen, sulfur, and oxygen. It is believed that crude oil and natural gas are the products of huge overburden pressure and heating of organic materials over millions of years. Crude oil and natural gases are formed as a result of the compression and heating of ancient organic materials over a long period of time. Oil, gas, and coal are formed from the remains of zooplankton, algae, terrestrial plants, and other organic matters after exposure to heavy pressure and temperature of earth. These organic materials are chemically changed to kerogen. With more heat and pressure along with bacterial activities, oil and gas are formed. Fig. 8.1 is the pathway of crude oil and gas formation. These processes are all driven by natural forces.

8.2.2 Pathways of oil refining Fossil fuels derived from the petroleum reservoirs are refined to suit the various application purposes from car fuels to aeroplane and space fuels. It is a complex mixture of hydrocarbons varying in composition depending on its source. Depending on the number Biomass Decay and degradation Natural processes

Burial inside earth and ocean floors for millions of years Kerogen formation Bacterial action, heat, and pressure Bitumen, crude oil and gas formation

FIGURE 8.1

Crude oil formation pathway. Redrawn from Chhetri and Islam, 2008.

8.2 Environmental sustainability of petroleum operations

621

Vacuum distillation

Crude oil storage and transportation

Atmospheric distillation

Hydrocarbon separation Cracking, Coking etc. Hydrocarbon creation

Alkylation, reforming etc

Hydrocarbons blending

Removal of sulfur other chemicals

Cleaning impurities

Solvent dewaxing, caustic washing

FIGURE 8.2 General activities in oil refining. Redrawn from Chhetri and Islam, 2007b.

of carbon atoms the molecules contain and their arrangement, the hydrocarbons in the crude oil have different boiling points. To take the advantage of the difference in boiling point of different components in the mixture, fractional distillation is used to separate the hydrocarbons from the crude oil. Fig. 8.2 shows general activities involved in oil refining. Petroleum refining begins with the distillation or fractionation of crude oils into separate hydrocarbon groups. The resultant products of petroleum are directly related to the properties of the crude processed. Most of the distillation products are further processed into more conventionally usable products changing the size and structure of the carbon chain through several processes by cracking, reforming, and other conversion processes. To remove the impurities in the products and improve the quality, extraction, hydrotreating, and sweetening are applied. Hence, an integrated refinery consists of fractionation, conversion, treatment, and blending including petrochemicals processing units. Oil refining involves the use of different types of acid catalysts along with high heat and pressure (Fig. 8.3). The process of employing the breaking of hydrocarbon molecules is the thermal cracking. During alkylation, sulfuric acids, hydrogen fluorides, aluminum chlorides, Boiler

Crude Oil

Heat, pressure, acid catalysts

Cracking

H2SO4, HF, AlCl3, Al2O3, Pt as catalysts

Alkylation

Platinum, nickel, tungsten, palladium

Hydro processing

High heat/pressure

Distillation

Distillation

Other methods

FIGURE 8.3

Pathway of oil refining process. Redrawn from Islam, 2010.

622

8. Environmental sustainability

and platinum are used as catalysts. Platinum, nickel, tungsten, palladium, and other catalysts are used during hydroprocessing. In distillation, high heat and pressure are used as catalysts. The use of these highly toxic chemicals and catalysts creates several environmental problems. Their use will contaminate the air, water, and land in different ways. Use of such chemicals is not a sustainable option. The pathway analysis shows that current oil refining process is inherently unsustainable. Refining petroleum products emits several hazardous air toxins and particulate materials. They are produced while transferring and storage of materials and during hydrocarbon separations. Table 8.1 shows the emission released during the hydrocarbon separation process and handling. Table 8.2 shows the primary waste generated from an oil refinery. In all processes, air toxics and hazardous solid materials, including volatile organic compounds, are present. There are various sources of emissions in the petroleum refining and petrochemical industries, and the following are the major categories of emission sources (US EPA, 2008).

TABLE 8.1

Emission from a refinery (from Islam, 2020).

Activities

Emission

Material transfer and storage

- Air release: Volatile organic compounds (VOCs) - Hazardous solid wastes: anthracene, benzene, 1,3-butadiene, curnene, cyclohexane, ethylbenzene, ethylene, methanol, naphthalene, phenol, PAHs, propylene, toluene, 1,2,4-trimethylbenzene, xylene

Separating hydrocarbons

- Air release: Carbon monoxide, nitrogen oxides, particulate matters, sulfur dioxide, VOCs - Hazardous solid waste: ammonia, anthracene, benzene, 1,3-butadiene, curnene, cyclohexane, ethylbenzene, ethylene, methanol, naphthalene, phenol, PAHs, propylene, toluene, 1,2,4-trimethylbenzene, xylene

PAHs,polycyclic aromatic hydrocarbons.

TABLE 8.2

Primary wastes from oil refinery (from Islam, 2020).

Cracking/coking

Alkylation and reforming

Air releases: Carbon monoxide, nitrogen, Air releases: Carbon monoxide, oxides, particulate matter, sulfur, nitrogen oxides, particulate matter, dioxide, VOCs sulfur dioxide, VOCs Hazardous/solid wastes, wastewater, ammonia, anthracene, benzene, 1,3butadiene, copper, cumene, cyclohexane, ethylbenzene, ethylene, methanol, naphthalene, nickel, phenol, PAHs, propylene, toluene, 1,2,4trimethylbenzene, vanadium (fumes and dust), xylene

Hazardous/solid wastes: ammonia, benzene, phenol, propylene, sulfuric acid aerosols or hydrofluoric acid, toluene, xylene, Wastewater

PAHs, polycyclic aromatic hydrocarbons; VOCs, volatile organic compounds.

Sulfur removal Air releases: Carbon monoxide, nitrogen oxides, particulate, matter, sulfur dioxide, VOCs Hazardous/solid wastes: ammonia, diethanolamine, phenol, metals, Wastewater

8.3 Current practices in exploration, drilling, and production

623

8.2.2.1 Process emissions In petroleum refining and petrochemical industries, the typical processes that take place include separations, conversions, and treating processes, such as cracking, reforming, isomerization, and so on. The emissions arising from these processes are termed as process emissions and are typically released from process vents, sampling points, safety valve releases, and similar items. 8.2.2.2 Combustion emissions Combustion emissions are generated from the burning of fuels, which is done for production and transportation purposes. The nature and quantity of emissions depends upon the kind of fuel being used. Generally, combustion emissions are released from stationary fuel combustion sources such as furnaces, heaters, and steam boilers, but they can also be released from flares, which are used intermittently for controlled release of hazardous materials during process upsets. 8.2.2.3 Fugitive emissions Fugitive emissions include sudden leaks of vapors from equipment or pipelines, as well as continuous small leaks from seals on equipment. These emissions are not released from vents and flares but may occur at any location within a facility. Sources of fugitive emissions are mostly valves, pump and compressor, and piping flanges. Fugitive emissions are a source of growing concern, as their effective control requires good process safety mechanisms for mitigation, as well as ongoing lead detection and repair programs. 8.2.2.4 Storage and handling emissions These emissions are released from the storing and handling of natural gas, oil, and their derivatives. This is a potential problem in every petroleum refining and petrochemical industry, including any product distribution sites. Handling mainly includes loading and unloading operations for shipping products to customers. Although transport of many refinery products is through pipelines, some other means such as marine vessels and trucks also exist. In these cases, there might be emissions during material transfer to these vehicles. 8.2.2.5 Auxiliary emissions Auxiliary emissions originate from units such as cooling towers, boilers, sulfur recovery units, and wastewater treatment units. Atmospheric emissions from cooling towers mainly include gases, which are stripped when the water phase comes into contact with air during the cooling process. In wastewater treatment units, emissions may arise by stripping of the VOCs from contaminated wastewater in the pond, pits, drains, or aeration basins.

8.3 Current practices in exploration, drilling, and production Seismic exploration is examined for the preliminary investigation of geological information in the study area and is considered to be the safest among all other activities in petroleum operations, with little or negligible negative impacts on the environment. However, several studies have shown that it has several adverse environmental impacts (see Islam et al.,

624

8. Environmental sustainability

2010 for details). Most of the negative effects are from the intense sound generated during the survey. Seismic surveys can cause direct physical damage to a fish. High-pressure (HP) sound waves can damage the hearing system, swim bladders, and other tissues/systems. These effects might not directly kill the fish, but they may lead to reduced fitness, which increases their susceptibility to predation and decreases their ability to carry out important life processes. There might be indirect effects from seismic operations. If the seismic operation disturbs the food chain/web, then it will cause adverse impacts on fish and total fisheries. The physical and behavioral effects on fish from seismic operations are discussed in the following sections. It has also been reported that seismic surveys cause behavioral effects among fish. For example, startle response, change in swimming patterns (potentially including change in swimming speed and directional orientation), and change in vertical distribution are some of the effects. These effects are expected to be short term, with duration of effect less than or equal to the duration of exposure; they are expected to vary between species and individuals and be dependent on properties of received sound. The ecological significance of such effects is expected to be low, except where they influence reproductive activity. Some studies of the effects of seismic sound on eggs and larvae or on zooplankton were found. Other studies showed that exposure to sound may arrest development of eggs and cause developmental anomalies in a small proportion of exposed eggs and/or larvae; however, these results occurred at numbers of exposures much higher than are likely to occur during field operation conditions, and at sound intensities that only occur within a few meters of the sound source. In general, the magnitude of mortality of eggs or larvae that could result from exposure to seismic sound predicted by models would be far below that which would be expected to affect populations. Similar physical, behavioral, and physiological effects in the invertebrates are also reported. Marine turtles and mammals are also significantly affected due to seismic activities. The essence of all exploration activities hinges upon the use of some form of wave that would depict subsurface structures. It is important to note that practically all such techniques use artificial waves, generated from sources of variable level of radiation. There exists a correlation between the energy levels and the wavelength of photon energy (Fig. 8.4). It is shown that the energy level of photon decreases with the increase in wavelength. The sources that generate waves that penetrate deep inside the formation are more likely to be of highenergy level, hence more hazardous to the environment. Photon Energy 10keV 1keV

0.1keV 0.01 keV Wave Length 0.1nm

1 nm

10 nm

100 nm

FIGURE 8.4 Schematic of wavelength and energy level of photon. From Islam et al., 2010.

625

8.3 Current practices in exploration, drilling, and production

TABLE 8.3

Wavelength and quantum energy levels of different radiation sources.

Radiation

Wavelength

Quantum energy

Infrared

1e750 nm

0.0012e1.65 eV

Visible

750e400 nm

1.65e3.1 eV

Ultraviolet

400 e10 nm

3.1e124 eV

X-rays

10 nm

124 eV

g-rays


12

10

m

1 MeV

From Islam et al., 2015.

Table 8.3 shows the quantum energy level of various radiation sources. The g-rays that have the least wavelength have the highest quantum energy levels. In terms of intensity, g-rays have highest energy intensity among others. More energy is needed to produce this radiation whether to use for drilling or any other application. For instance, laser drilling, which is considered to be the wave of the future, will be inherently toxic to the environment. Drilling and production activities have also adverse effects on the environment in several ways. For example, blow-out and flaring of produced gas waste energy, carbon dioxide emissions into the atmosphere, and careless disposal of drilling mud and other oily materials can have a toxic effect on terrestrial and marine life. Before drilling and production operations are allowed to go ahead, the valued ecosystem component (VEC)elevel impact assessment should be done to establish the ecological and environmental conditions of the area proposed for development and assess the risks to the environment from the development.

8.3.1 Key to sustainability From the beginning of oil recovery, scientists have been puzzled by the huge amount of oil leftover following primary recovery. Naturally occurring drive mechanisms recover anything from 0% to 70% of the oil in place. In most cases, recovery declines rapidly, as viscosity of oil increases. For instance, primary recovery is less than 5% when oil viscosity exceeds 100,000 cp. This is not to say that heavy oil recovery was the primary incentive for enhanced oil recovery (EOR), even though most EOR projects in the United States, Canada, and Venezuela involve heavy oil recovery. The primary incentive for EOR is the fact that a typical light oil reservoir would have more than 50% of the original oil in place leftover, while a small investment can recover over 70% of the oil in place. For heavy oil, the room for improvement is much higher. Even though theoretically there is much more recovery potential of heavier energy sources all the way up to biomass (Fig. 8.5), the current recovery techniques are geared toward light oil. This figure shows that natural gas is the most efficient with the most environmental integrity. The argument that is made in this figure is that if natural gas, light oil, or any other energy source is burnt without adding artificial chemicals in the stream (e.g., during refining), the entire combustion output is fully sustainable and the CO2 that is produced is 100% recyclable. Each molecule of produced CO2 would end up, contributing to the formation of greeneries. Greeneries then end up as biomass, which contribute to enriching the ecosystem. As such, the energy resource is infinity as long as sustainability is maintained.

626

8. Environmental sustainability

FIGURE 8.5 Key to sustainability in energy management. Redrawn from Islam, M.R., 2020. Environmentally and Economically Sustainable Enhanced Oil Recovery. Wiley-Scrivener. pp. 791.

FIGURE 8.6 Distribution of world’s proven reserve. From Islam, M.R., 2020. Environmentally and Economically Sustainable Enhanced Oil Recovery. Wiley-Scrivener. pp. 791.

Within petroleum itself, the “proven reserve”1 is nearly 1.7 trillion barrel (BP, 2018). Out of this reserve, conventional light oil is only 30% (Fig. 8.6). It means that devising a thermal EOR technique is paramount. Any thermal EOR technique involves adding heat, which increases the mobility of the oil exponentially. Fig. 8.7 shows one example of such exponential decrease in viscosity, which correlates directly with flow rate. The task in hand becomes the delivery of sustainable heat to the formation. The “easy oil,” which is the target of “oil wars,” involves only miniscule compared with the overall potential, as depicted in Fig. 8.8. Because all energy source utilization techniques are equipped with processing light oil as a reference, the primary focus of EOR has been light oil. A much larger portion of the global oil reserve involves heavy oil, tar sand, shale, and other reservoirs, which require some form of EOR to produce. This reserve can be doubled by using sustainable technology, which increases the overall efficiency and can be utilized in otherwise marginal oil reservoirs. Use of such technology can double the current reserve, 1

Proven oil reserves are reserves that are known to exist and that are recoverable under current technological and economic conditions.

8.3 Current practices in exploration, drilling, and production

627

FIGURE 8.7 Viscosity change invoked by temperature. From Islam, M.R., 2020. Environmentally and Economically Sustainable Enhanced Oil Recovery. Wiley-Scrivener. pp. 791.

FIGURE 8.8 Much more oil can be recovered with double dividend of environmental benefit with sustainable technologies. From Islam, M.R., 2020. Environmentally and Economically Sustainable Enhanced Oil Recovery. WileyScrivener. pp. 791.

even when no new technology is implemented. When the potential of novel technologies is included, a much bigger oil reserve becomes accessible. Most importantly, the exploitation of oil with sustainable technology produces only environmentally friendly gases that are readily assimilated with the ecosystem. With it comes the double dividend of economic benefit because all truly sustainable technologies are also the least expensive.

628

8. Environmental sustainability

FIGURE 8.9

Profitability grows continuously with time when zero-waste oil recovery.

Fig. 8.9 demonstrates the need for using natural and waste materials. EOR involves making up for the loss of natural production cycle to meet the growing need of petroleum. However, for reservoirs with high reserve/production ratio, it is most cost-effective to infill drill. By carefully selecting infill drilling sites, the recovery factor can be increased even with primary production mode. The economics of any operation changes drastically if waste gas, produced gas or locally available gas, is used. Fig. 8.10 presents a qualitative comparison among various modes of EOR. This figure shows how local fluid injection gives higher return in investment than conventional turn key projects, even though the return is lower at early stages of EOR. Using local fluid requires more investment in infrastructure than turn key projects, but the investment pays off quickly, and much higher return is posted at later stages.

FIGURE 8.10

For the same investment, return is much different depending on type of fluid injected.

8.3 Current practices in exploration, drilling, and production

FIGURE 8.11

Drilling activities in the United States for various years (EIA, 2014).

FIGURE 8.12

Uncompleted drilling activities in the United States. From EIA, 2019.

629

Local fluids may be produced hydrocarbon gas, locally available CO2, or other gas/fluid available in and around the reservoir. Waste gas, on the other hand, shows higher return throughout the duration of the project. Waste gas may include produced hydrocarbon gas that is normally flared, flue gas, sour gas, or any others that are considered to be liability to the producer. Fig. 8.11 shows drilling activities in the United States over the past decade. This represents enhanced level of drilling throughout to match with the production boost during the same period. Note that the reserve/recovery ratio in the United States is quite low. Such intense drilling activities would represent far greater output in high ratio reservoirs. As stated earlier, infill drilling can increase both production rate and recoverable reserve for cases for which reserve/recovery ratio is low, as is in most OPEC (Organization of the Petroleum Exporting Countries) countries. The number of drilled but uncompleted wells in seven key oil and natural gas production regions in the United States has increased over the past 2 years, reaching a high of 8504 wells in February 2019, according to well counts in EIA’s Drilling Productivity Report (DPR). The most recent count, at 8500 wells in March 2019, was 26% higher than the previous March (Fig. 8.12).

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8. Environmental sustainability

FIGURE 8.13 Locations of uncompleted drilled wells. From EIA, 2019.

Drilled but uncompleted wells, also known as DUCs, are oil and natural gas wells that have been drilled but have not yet undergone well completion activities to start producing hydrocarbons. The well completion process involves casing, cementing, perforating, hydraulic fracturing, and other procedures required to produce crude oil or natural gas. The number of DUCs has generally increased since the end of 2016. A high inventory of DUCs may be attributable to economic factors or resource constraints. For example, a low oil and natural gas price environment may postpone well completion activities in areas where the wellhead break-even price is too high relative to the current market price. Another example may be the lack of available well completion crews to perform hydraulic fracture activities in areas of high demand. Takeaway capacity, or the ability to transport hydrocarbons through pipelines away from the resource, may also place additional constraints when pipeline networks are insufficient to accommodate supply. Most of the recent increase in the DUC count has been in regions dominated by oil production, especially the Permian region that spans western Texas and eastern New Mexico. As of March 2019, nearly half of the total DUCs included in the DPR were in the Permian region. The Permian Basin experienced takeaway constraints in the second half of 2018, but recent pipeline capacity additions in the region have reduced some of the takeaway constraints. Other pipeline projects are planned or currently under construction. In contrast to oil-directed regions, the number of DUCs in natural gasedominated DPR regions such as the Appalachian and Haynesville regions has decreased by nearly half over the past 3 years, from 1230 wells in March 2016 to 713 wells in March 2019. New pipelines in these regions have increased the ability to transport natural gas to demand centers in the Northeast and Midwest (Fig. 8.13). The overall picture of conventional refining and how it can be transformed is given in Fig. 8.14. The economics of this transition is reflected in the fact that the profit made through conventional refining would be directly channeled into reduced cost of operation (Fig. 8.14). This figure amounts to the depiction of a paradigm shift. The task of reverting to natural from unnatural has to be performed for each stage involved in the petroleum refining

8.3 Current practices in exploration, drilling, and production

FIGURE 8.14

631

Natural chemicals can turn a sustainable process into a sustainable process.

sector. Table 8.4 shows various processes involved and the different derivatives produced. Note that each of the products later becomes a seed for further use in all aspects of our lifestyle. As a consequence, any fundamental shift from unsustainable to sustainable would reverberate globally.

632 TABLE 8.4

8. Environmental sustainability

Overview of petroleum refining processes. (data from US Dept of Labor, as reported by Speight, 2014).

Process name

Action

Method

Purpose

Feedstock(s)

Product(s)

Fractionation processes Atmospheric distillation

Separation

Thermal

Separate fractions

Desalted crude oil

Gas, gas oil, distillate, residual

Vacuum distillation

Separation

Thermal

Separate without cracking

Atmospheric tower residual

Gas oil, lube stock, residual

Conversion processesddecomposition Catalytic cracking

Alteration

Catalytic

Upgrade gasoline

Gas oil, coke distillate

Gasoline, petrochemical feedstock

Coking

Polymerize

Thermal

Convert vacuum residuals

Gas oil, coke distillate

Gasoline, petrochemical feedstock

Hydrocracking

Hydrogenate

Catalytic

Convert to lighter Gas oil, cracked hydrocarbons (HCs) oil, residual

a Hydrogen steam reforming

Decompose

Thermal/ catalytic

Produce hydrogen

Desulfurized gas, Hydrogen, CO, CO2 O2, steam

a

Decompose

Thermal

Crack large molecules

Atmospheric tower, heavy fuel/distillate

Cracked naphtha, coke, residual

Visbreaking

Decompose

Thermal

Reduce viscosity

Atmospheric tower residual

Distillate, tar

Combining

Catalytic

Unite olefins and isoparaffins

Tower isobutane/ cracker olefin

Iso-octane (alkylate)

Grease compounding Combining

Thermal

Combine soaps and Lube oil, fatty Lubricating grease oils acid, alkyl metal

Polymerizing

Catalytic

Unite two or more olefins

Steam cracking

Lighter, higherquality products

Conversion processesdunification Alkylation

Polymerize

Cracker olefins

High-octane naphtha, petrochemical stocks

Conversion processesdalteration or rearrangement Catalytic reforming

Alteration/ dehydration

Catalytic

Upgrade low-octane Coker/ naphtha hydrocracker naphtha

High-octane reformate/aromatic

Isomerization

Rearrange

Catalytic

Convert straight chain to branch

Butane, pentane, Isobutane/pentane/ hexane hexane

Treatment

Absorption

Remove acidic contaminants

Acid-free gases and Sour gas, HCs w/CO2 and H2S liquid HCs

Treatment processes Amine treating

633

8.4 Sour gas

TABLE 8.4

Overview of petroleum refining processes. (data from US Dept of Labor, as reported by Speight, 2014).dcont’d

Process name

Action

Method

Purpose

Feedstock(s)

Product(s)

Desalting

Dehydration

Absorption

Remove contaminants

Crude oil

Desalted crude oil

Drying and sweetening

Treatment

Absorption/ Remove H2O and sulfur compounds thermal

Liquid HCs, LPG, alkyl feedstock

Sweet and dry hydrocarbons

a

Solvent extraction

Absorption

Upgrade middistillate and lubes

Cycle oils and lube feedstocks

High-quality diesel and lube oil

Catalytic

Remove sulfur, contaminants

High-sulfur residual/gas oil

Desulfurized olefins

Furfural extraction

Hydrodesulfurization Treatment Hydrotreating

Hydrogenation Catalytic

Phenol extraction

Solvent extraction

Remove impurities, Residuals, saturate HCs cracked HCs

Cracker feed, distillate, lube

Absorption/ Improve viscous thermal index, color

Lube oilebased stocks

Solvent deasphalting Treatment

Absorption

Remove asphalt

Vacuum tower Heavy lube oil, residual, propane asphalt

Solvent dewaxing

Treatment

Cool/filter

Remove wax from lube stocks

Vacuum tower lube oils

Dewaxed lube basestock

Solvent extraction

Solvent extraction

Absorption/ Separate precipitation unsaturated oils

Gas oil, reformate, distillate

High-octane gasoline

Sweetening

Treatment

Catalytic

Untreated distillate/ gasoline

High-quality distillate/gasoline

Remove H2S, convert mercaptan

High-quality lube oils

Note: These processes are not depicted in the refinery process flowchart.

a

8.4 Sour gas In the field of natural gas and petroleum engineering, sour gas refers to gas with high concentrations of sulfur compounds. The most common of these compounds is hydrogen sulfide (H2S). There are several other sulfur compounds found in natural gas and petroleum fluids. These include mercaptans (also known as thiols), sulfides, disulfides, carbon disulfide (CS2), and carbonyl sulfide (COS). Another important sulfur compound is sulfur dioxide, SO2. Although not found in significant amount in natural gas or petroleum stream, SO2 is

634

8. Environmental sustainability

formed from the combustion of sulfur compounds. It is a colorless with the characteristic foul odor of rotten eggs. It is very poisonous, corrosive, and flammable. Hydrogen sulfide is notorious for being poisonous at relatively low concentrations and for its foul odor at even lower concentrations. In fact, at higher and fatal concentrations, H2S is not detectible with our olfactory senses. The definition of sour gas varies from jurisdiction to jurisdiction and from application to application. For example, what for raw gas to be considered sweet is very different from sales gas. For raw gas, the main interest is the emergency planning. Thus, gas that requires no emergency exclusions zones would be considered sweet. According to the Energy Resources Conservation Board (RCB) in the province of Alberta, “sour gas is natural gas that contains measurable amounts of hydrogen sulfide”. “Measurable” is the operative word. In oilfield terms, “measurable” typically means about 100 parts per million (ppm) or 0.01 mol%. As such, a simpler definitions for raw gas would be (Wu et al., 2012) sweetdraw gas less than 100 ppm H2S low sour gasdless than 1% H2S, but greater than 100 ppm. moderate sour gasdbetween 1% and 10% H2S high sour gasdbetween 10% and 25% H2S ultrahigh sour gasdgreater than 25% H2S Any area with 100 ppm H2S would be very dangerous for humans and animals. However, raw gas having 100 ppm concentration would be diluted with fresh air if released to the atmosphere. Therefore, exclusion zones for the production of gas containing 100 ppm H2S would be limited to the immediate area around the well, pipeline, and processing facilities. Burgers et al. (2011) summarized data on the location and scale of proven and probable sour gas resources and compared with size and location of oil fields. At present, these resources are being considered for carbon capture for carbon dioxide EOR. The focus is to sequester CO2. The high CO2 content between 15% and 80%, as well as in some cases the addition of hydrogen sulfide (H2S), severely limits the economic and environmental viability of sour gas resources. Globally, a total resource of around 4 trillion m3 of net hydrocarbon gas and 15,000 MT of associated CO2 has been identified. This was done by summing individual undeveloped and underdeveloped fields with ultimate recoverable proven and probable resources larger than 14 billion m3 each of net hydrocarbon gas and CO2 content between 15% and 80%. Development of these fields could be enabled by the availability of a cost-effective gas separation method such as the Controlled Freeze Zone (CFZ) technology and viable CO2EOR opportunities (CO2-EOR) to reduce the cost of CO2 capture, transportation, and storage. The same sour gas resources, which have been mapped globally using the IHS fields and reservoirs database from 2009 (Burgers et al., 2011), can be used for developing sulfur resources. The largest concentrations of sour gas are located in SE Asia and NW Australia, Central USA, Middle East, and North Africa. In the United States, Middle East, and North Africa, which are oil rich, there is significant potential for CO2-EOR opportunities. The relative absence of significant oil accumulations in SE Asia and NW Australia will in many cases require the storage of CO2 in saline aquifers, as is planned for the Gorgon field in Australia. The challenges of developing natural gas fields with a high CO2 content can be best illustrated by ExxonMobil’s development of the LaBarge field. This field, located in SW

8.4 Sour gas

635

Wyoming, USA, was discovered in 1963, but production was delayed until 1986, because of the challenging gas composition of 65% carbon dioxide, 21% methane, 7% nitrogen, 5% hydrogen sulfide, and 0.6% helium. It is the lowest hydrocarbon content natural gas commercially produced in the world. The remote location relative to potential EOR opportunities and the absence of infrastructure for the transportation of CO2 limited the early development of the CO2 resources in LaBarge. Since, however, the increased recognition of the benefits of CO2-EOR to improve the recovery from the aging oil resources has allowed the expansion of the CO2 transportation infrastructure. Currently, the majority of the recovered CO2 is transported and sold to EOR operators. ExxonMobil has continually enhanced its capabilities to capture and manage CO2 at LaBarge. It uses Selexol, a physical solvent, to remove CO2 and H2S from the natural gas. H2S was initially converted to elemental sulfur, but subsequently is being disposed of, along with a small portion of the CO2, by acid gas injection (AGI) into a selected section of the same reservoir from which it is produced. Other technologies and approaches that have reduced CO2 emissions include the ExxonMobil patented low BTU fuel cogeneration system that substantially reduces CO2 emissions when compared with emissions from purchased power (Burgers et al., 2011). Additionally, new technologies are being developed that may provide additional reductions in emissions, either at this site or at others with similarly challenged production streams. Construction of a commercial demonstration facility for ExxonMobil’s CFZ gas treatment technology has been completed at Shute Creek, and operations are about to begin. The CFZ technology allows the single step separation of CO2 and other contaminants from a natural gas stream without the use of solvents or absorbents. Its successful commercial demonstration would enable the development of increasingly sour gas resources around the world by substantially reducing gas treatment and geosequestration costs from these sources (Burgers, 2011). Whenever HP and high-temperature (HT) conditions prevail in a well, in presence of environments (i.e., high H2S and/or CO2 content), many new challenges surface are becoming more and more common (Van Wittenberghe et al., 2010). On the other hand, with the wide application of formation stimulation method such as acid fracture, as well as the untreated drilling mud (Puthalath et al., 2012), a corrosive environment is induced on the steel pipes. Moreover, in recent years, because of new technologies such as EOR methods (Wang and Zhang, 2015) and carbon capture and storage methods (Choi et al., 2013, 2015), the aggressive fluids with HP become more and more aggressive to the steels (Sim et al., 2014).

8.4.1 Trends in oil, natural gas, and sour gas contents Fig. 8.15 shows the history of US crude oil proved reserve. Prior to 2008, there was overall decline in US reserve. Beyond 2008, upon expansion in the unconventional oil and gas formations, there has been a steady rise in the reserve. Of course, the proved reserve is linked to oil price, in the sense that a low oil price can render certain reserve untenable with the current technology cost. For instance, in 1980, proved reserves in the United States were 36.5 billion barrels. At the 1980 rate of US production, that was enough oil for just over 10 years of production. Of course, that did not happen. In reality, between 1980 and the end of 2014, the United States produced 111 billion barrels of oil. Despite the 111 billion barrels that were produced, US crude oil reserves at the end of 2014 had grown to 48 billion barrels. On the other hand, the sharp increase since 2008 is due to both oil price and technological

636

FIGURE 8.15

8. Environmental sustainability

History of US crude oil and lease condensate proved reserve. Data from EIA reports, BP, 2018.

advancement. Oil at $100/bbl enabled the shale oil boom by making it economical to combine hydraulic fracturing (“fracking”) and horizontal drilling in previously uneconomical formations. This pushed a lot of oil from the resource category into the proved reserves category. Similarly, the decline in oil reserve in 2014 is due to oil price collapse. Contrary to the US reserve, the global reserve has maintained a consistent pattern. For instance, in 1980, the global oil reserve was 683 billion barrels, which has burgeoned to 1.7 trillion barrels in 2014. Natural gas has maintained similar trends in the United States. Fig. 8.16 shows the history of natural gas reserve in various locations of the United States. Both federal offshore and Alaska show steady decline in the reserve, whereas reserve in the lower 48 onshore has been fluctuating (due to the points discussed earlier), leading to total reserve showing fluctuations.

FIGURE 8.16

US reserve variation in recent history. From EIA, 2018.

8.4 Sour gas

FIGURE 8.17

637

US gas production history (EIA, 2018).

Fig. 8.17 shows gas production history of the United States. Gas production has been steadily rising with anomalies showing during the oil embargo of 1973 and during the 1990s and the early 2000s. After 2008, however, the reserve has increased at a greater pace than before. This is the time when the so-called gas war in Europe took place that saw great hikes in gas price. Fig. 8.18 shows the gas reserve production (R/P) ratio of the United States. The numbers are similar to the oil R/P values. However, the trends are not similar. It is because gas prices have been governed by different set of rules from those of oil prices (Zatzman, 2012).

FIGURE 8.18

US gas reserve production history. Data from EIA, 2018.

638

8. Environmental sustainability

FIGURE 8.19

Sulfur content of the US crude over the past few decades. From EIA, 2019.

FIGURE 8.20

Declining API gravity of US crude oil. From EIA, 2019.

One important criterion in EOR is the quality of crude oil, in terms of composition as well as physical properties. Fig. 8.19 shows steady increase in sulfur content in US crude. This graph is based on data at the inlet of refineries. Fig. 8.20 shows that the API gravity of crude oil in the United States has declined steadily. Any change of the quality of the crude implies both economic and technological drain on the crude oil. Light sweet grades are desirable because they can be processed with far less sophisticated and energy-intensive processes/refineries. One particular advantage of certain EOR techniques is in situ upgrading of in situ oil. While no data is available on the quality of oil recovered with EOR as compared with the same without EOR, it is reasonable to assume that in situ upgrading would improve the quality of produced oil. Recently, Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention) limited emissions for ocean-going ships by 2020 (IMO, 2020). From January 1, 2020, the limit for sulfur in fuel used on board ships operating outside designated emission control areas will be reduced to 0.5% m/m (mass by mass), a reduction of

8.4 Sour gas

639

FIGURE 8.21 Decline in high-sulfur fuel consumption. From EIA, 2019.

more than 85% from its present level of 3.5% m/m. Ships can meet the new global sulfur limit by installing pollutant-control equipment by using a low-sulfur, petroleum-based marine fuel or by switching to an alternative nonpetroleum fuel such as liquefied natural gas (LNG). However, shippers that install scrubbers have remained limited, and refineries continue to announce plans to upgrade high-sulfur fuel oils into higher-quality products and increase availability of low-sulfur compliant fuel oils. Fig. 8.21 shows the expected decline in the use of high-sulfur fuel oil. The selected crude oils in Fig. 8.22 show the “sweetness” of various crude oils from around the world. These grades were selected for the recurrent and recently updated EIA report, “The Availability and Price of Petroleum and Petroleum Products Produced in Countries Other Than Iran” (EIA, 2016). This figure shows that a comprehensive EOR scheme should include provisions to accommodate or otherwise utilize sulfur that is produced with crude oil. Fig. 8.23 shows unconventional oil production in the United States along with projection under two different scenarios.

8.4.2 Casing and strategies for sour gas containing petroleum Many oil and gas wells contain large amounts of H2S and CO2, posing severe challenges for drilling and production operations. Apart from drilling safety issues, they pose extreme vulnerability to corrosion; thus, selection of production casing materials must be considered carefully. Eliyan and Alfantazi (2014) analyzed the effect of corrosion product film on corrosion rate through the microscopic structure. They studied the interrelation between the corrosion reactions, the growth and characteristics of the corrosion products, and the microstructures of simulated heat-affected zones (HAZs) from API-X100 steel. In saline CO2-saturated solutions, the corrosion products were found to suppress more the anodic dissolution than the cathodic reactions. The corrosion products of ferritic microstructures are thicker and of higher cathodic currents than those of acicular-ferritic and martensitic

640

8. Environmental sustainability

Density and sulfur content of selected crude oils sulfur content (percentage)

sour 3.5 Mexico - Maya Saudi Arabia - Arab Heavy

3.0

Kuwait - Kuwait

2.5 United States Mars

2.0

Iran - Iran Heavy 1.5 1.0

UAE - Dubai Saudi Arabia - Arab Light Iran - Iran Light FSU - Urals Oman - Oman

Ecuador - Oriente North Sea - Brent

0.5

sweet

Libya - Es Sider Nigeria - Bonny Light

0.0 20

heavy

25

30

35

United States - WTI Algeria - Sahara United States - LLS 40

Blend Malaysia - Tapis 45 50

API gravity (a measure of curde oil density)

FIGURE 8.22

light

Worldwide crude oil quality. From Islam, 2014. Notes: Point on the graph are labeled by country and benchmark name and are color coded to correspond with regions in the map below. The graph does not indicate price or volume output values. United States-Mars is an offshore drilling site in the Gulf of Mexico. FSU- Former Soviet Union; LLS- Louisiana Light Sweet; UAE- United Arab Emirates; WTI- West Texas Intermediate. Sources : U.S. Energy Information Administration, based on Energy Intelligence Group d International Crude Oil Market.

FIGURE 8.23

Projection of tight oil under different conditions. From EIA, 2019.

8.4 Sour gas

641

microstructures, which are intrinsically less reactive. The significances of chloride, iron oxides, and Fe3C with the growth and reactivity of the corrosion products were explored. The cathodic polarization currents were found to be higher for thicker corrosion products. This was ascribed to the dissolution of the products, the greater amounts of the conductive iron oxides and Fe3C, and the possibility for the cathodic reactions to be more under masstransfer control. Quanan et al. (2004) compared the thickness and grain size of CO2 corrosion production film under different temperatures and established the relationship between temperature and the production film. For the operating conditions on corrosion, Sellaturay et al. (2014) analyzed temperature, the effect of flow rates, bicarbonate content, organic acid content, H2S, and CO2 partial pressure on corrosion rate. Song and Nogueira (2014) presented three corrosion studies on subsea production flowline systems from three different offshore sample fields at the design stage. The effects of the key operating conditions (temperature and flowrates) and water chemistry (bicarbonate content, organic acid content, and H2S and CO2 partial pressure) on the predicted corrosion rates were discussed. Both mechanistically based corrosion model and empirical models have been used. It has been found that the corrosion rates can be relatively high when both CO2 partial pressure, above 448 kPa (65 psi), and water production rate, above 1590 m3/d (10,000 BPD), are at such high levels for a multiphase flowline system. In such cases, a carbon steel flowline solution is too risky, even when applying a corrosion inhibition system. For a gas production flowline system containing organic acids and CO2, a potential solution is to inject pH buffer (e.g., bicarbonate), in addition to traditional film-forming inhibitors. The structure of tubular is complicated, and the corrosion mechanism is affected by a series of comprehensive factors. Barik et al. (2005) and Postlethwaite and Nesic (1993) introduced numerical methods to study solideliquid two-phase flow-induced corrosion near the wall. Through scanning electron microscopy, X-ray diffraction, and the analysis of polarization curves, Liu et al. (2014) studied immersion tests combined with electrochemical measurements. Effects of chloride content on CO2 corrosion of carbon steel, combined with immersion tests, electrochemical measurements, scanning electron microscopy, X-ray diffraction, and analysis of polarization curves, revealed an interesting feature. Fig. 8.24 shows the variation in corrosion rate of N80 carbon steel with different Cl
contents (0e150 g/L) at a CO2 partial pressure of 20 bar and temperature of 100 C. The curve shows the existence of an optimum near 25 ppm. The corrosion rate increases sharply with increasing Cl
content and reaches the maximum value at 25 g/L. The corrosion rate sharply decreases as the Cl
content increasing from 25 to 100 g/L and then gradually decreases between 100 and 150 g/L. This finding has great significance on oilfield applications, where salinity may vary widely. Amani and Hjeij (2015) found that the proper choice of materials, protective coatings, chemical inhibitors, and other corrosion control methods can reduce the rate of corrosion in drilling and production operations. Zhang and Wang (2017) reported a detailed analysis of a high-pressure high-temperature (HPHT) gas well in the west part of the South China Sea. Their analysis shows that the increasing thermal expansion annulus pressure might prominently reduce the cement sheath safety factor. The cement sheath safety factor decreased quickly when the thermal expansion annulus pressure is under 18 MPa. For the case well, the maximum thermal expansion pressures of annulus A, B, and C are 39, 24.4, and 18.5 MPa, respectively, the production

642

8. Environmental sustainability

FIGURE 8.24 Corrosion rates of the N80 steel in solution with different Cl
contents at a CO2 partial pressure of 20 bar and temperature of 100 C after 72 h of exposure. Redrawn from Liu, Q.Y., L.J. Mao, S.W. Zhou, 2014. Effects of chloride content on CO2, corrosion of carbon steel in simulated oil and gas well environments. Corrosion Science 84 (84), 165e171.

did not exceed 98.6  104 m3/d. The cement sheath safety factor was maximum when the thermal expansion coefficients of casing, cement sheath, and formation are equal to each other. The iso-surfaces of the cement sheath safety factor under different thermal expansion annulus pressure and temperature were established to obtain the critical value of the relevant parameters including thermal expansion coefficients of casing, cement sheath and formation, elasticity modulus, and Poisson ratio as well as the temperature that satisfy the mechanical integrity of the cement sheath. With the assumption that if the cement sheath is in tension, the stress is positive and if the cement sheath is in compression, the stress is negative. The interface separation between the cement sheath and the casing or formation and/or cement cement sheath failure leads to overall failure, including tensile failure and compressive failure. As such, the safety factor of the cement sheath under different stress conditions can be calculated by the MohreCoulomb criterion as shown in Table 8.5: In thee above, s1 and s3 can be obtained by Eq. (8.1): s1 ¼ sqs ; s3 ¼ srs

TABLE 8.5

(8.1)

MohreCoulomb criterion for the cement sheath.

Relation among principle stresses

Description of the stress status

Failure criteria

Safety factor

s1  s3  0

Tensionetensionetension

s1  st

st/s1

0  s1  s3

Compressionecompressionecompression


s3  scc


s3/sc

s1  0  s3

Tensionecompressionecompression

s1/st
s3/scc  1

1/(s1/st
s3/sc)

Tensionetensionecompression From Zhang, Z., Wang, H., 2017. Effect of thermal expansion annulus pressure on cement sheath mechanical integrity in HPHT gas wells. Applied Thermal Engineering 118 (2017), 600e611.

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FIGURE 8.25 Distribution of the annulus temperature.

Their mathematical model was validated with both the wellhead temperature and the thermal expansion annulus pressure. They both increase at the beginning of production and then taper off and actually drop down at around 155 days to a stable value, after which some fluctuations occur. For the wellhead temperature, the largest relative error between the calculated data and the measured data is 7.9%; for the thermal expansion annulus pressure, the largest relative error between the calculated data and the measured data is 8.0%. This demonstrates that the models established in their work are reliable and accurate means of determining the temperature and the thermal expansion annulus pressure of HPHT gas wells. Fig. 8.25 shows the distribution of the annulus temperature in which the mud line is at the origin of the coordinate; the temperature of each annulus increases with the well depth; the inside annulus is hotter than the outside annulus; the temperature difference between the annuli gradually increases with the decreases of the well depth. This is mainly because the layer number of the annuli gradually increases in radial direction during the upward flow of the wellbore fluid, which results in the decreases of the overall heat transfer coefficient. Thus, the radial temperature gradient becomes larger. Figs. 8.26 and 8.27 display the impact of the thermal expansion annulus pressure and the free section length of all casings on the cement sheath safety factor.

FIGURE 8.26 Impact of the thermal expansion pressure of annulus A and the free section length of production casing on the cement sheath safety factor.

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FIGURE 8.27 Impact of the thermal expansion pressure of annulus B and the free section length of intermediate casing on the cement sheath safety factor.

These figures show that the cement sheath safety factor decreases with the increases of the thermal expansion annulus pressure and the decreasing tendency gradually becomes slight. When the thermal expansion annulus pressure is less than 18 MPa, the longer the free casing section is, the lower the cement safety factor is; when the thermal expansion annulus pressure is greater than 18 MPa, the free section length of casings has no effect on the cement sheath safety factor. Fig. 8.26 shows that when the thermal expansion annulus pressure exceeds 39 MPa, the cement sheath at the bottom of the free section of the production casing might be in mechanical failure; therefore, the maximum thermal expansion pressure of annulus A is 39 MPa. For the fixed structure gas well, the maximum production can be obtained from the maximum thermal expansion annulus pressure, which is helpful for operators to plan reasonable production to maintain the mechanical integrity of cement sheath. Chen et al. (2010) studied the corrosion rate of casing material in condensate gas field with different water content and rotational rate. After the test, they found that the corrosion rate of the samples increased with the rise of water content. Zhou et al. (2009) studied the multiphase corrosion behavior with CO2 in gathering and transportation pipelines with water content 5%, 30%, 60%, 90%, and 100%. They pointed out that with the rise of water content, the wettability of oil is decreased, and the corrosion rate is increased. Cao et al. (2017) summarized different kinds of corrosion problems and their mitigation, to more efficiently protect petroleum well tubulars from corrosion. They classified four types of corrosion: • • • •

sweet corrosion; sour corrosion; galvanic corrosion; and microbiologically induced corrosion.

They investigated the effects of environmental and material factors on the corrosion rate. They highlighted the need for including not only characteristics related to material properties but also connection properties and geometry tolerances to fulfill the well design requisites. Later on, the mitigation of OCTG corrosion is generally divided into three methods:

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application of appropriate corrosion-resistant materials such as process-controlled low-alloy steel (LAS) and corrosion-resistant alloy (CRA), application of inhibitors, and application of protective layers. Concerning the material development, the improvement of some of the required properties of steels can weaken the others (i.e., steel strength vs. anticorrosion property). Consequently, a careful balance is required, and limits exist for each modification of the individual properties. Interestingly, the material selection criteria between global leading manufacturers are very different, showing a complicated philosophy of material selection. And it should be stressed that no particular material is the cure for all corrosion. Concerning the chemical inhibitors, a variety of organic compounds with additives are designed. However, the mechanism of how inhibitors work is usually not known, systematic research is lacking, and empirical testing is still the major method to study the inhibitors, and there is no theoretic model to predict their efficiency. And because the inhibitors are almost oneto-one correspondent with the particular corrosion environment, the selection of inhibitors is mainly based on former experience. Concerning the protective layer, coatings (plastic coating and metallic coating) and lining are introduced as well as the respective advantages and limitations. Cao et al. (2017) identified three environmental degradation-related phenomena (in relation to H2S corrosion), namely, • weight loss corrosion in sour service, • localized corrosion (mainly pitting), and • sulfide stress cracking (SSC). Among them, SSC is said to have the highest risk for petroleum well tubulars, because the presence of H2S under certain level of pressure, temperature, pH, and tensile stress could cause catastrophic failure to steels. Also, as the crack propagation can take place very fast, even short and unexpected exposure to H2S must be considered before material selection. SSC effect was first reported in North America in 1950 (Perez, 2013). It is known that the presence of atomic hydrogen severely degrades the fracture resistance of high-strength metallic alloys. This process is also named as hydrogen embrittlement or hydrogen-induced cracking (HIC). There is a consensus that critical concentration of hydrogen must be reached at a potential crack site for failure. Atomic hydrogen can be introduced throughout the microstructure by manufacturing process, such as casting, welding, surface-chemical cleaning, and heat treatment, as well as by environmental exposure, such as cathodic reactions and gaseous hydrogen exposure. Those sites where hydrogen is accumulated are called “hydrogen traps” with higher hydrogen binding energy than the lattice. Traps are generally referred to lattice defects such as vacancies, dislocations, grain boundaries (Moderer et al., 2013), or microstructural features such as second-phase interfaces (Sourmail and Park, 2006). In addition to atomic hydrogen, the presence of tensile stresses is recognized as the other required factor for SSC. Tensile stress was reported to influence on hydrogen solubility in pure iron and AISI 4340 steel, and different relationships were proposed to explain the effect of stresses on solubility (Ahn et al., 2007). The actual mechanism of SSC includes a combination of chemical and electrochemical steps. A very simplified description of the mechanism is shown in Fig. 8.28. First, atomic hydrogen is produced by the proton reduction, and it is chemically adsorbed on the surface (Habs) (Eq. 8.2). Habs will be consumed either by H recombination (Eq. 8.5) or by

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FIGURE 8.28

Schematic representation of SSC mechanism. SSC, sulfide stress cracking.

absorption into the bulk of material and then diffusion into the material (Hdiff) (Eq. 8.4). In the oil and gas industry, H2S dissolved in an aqueous environment can inhibit the recombination reaction (Eq. 8.3), although the detailed mechanism of the action of H2S is not yet fully understood. So the hydrogen atoms are easily adsorbed on the steel surface and diffuse into the steel (Baer et al., 1984). The crack propagates when a critical concentration of atomic hydrogen is reached at a potential crack site of the material. This threshold depends on the material characteristic, temperature, tensile strength level, and the hydrogen concentration itself. Simultaneously, the anodic corrosion reaction of the steel happens on the surface of material. Hþþe
4Habs 2Habs4H2 Habs4Hdiff

(8.2) (8.3) (8.4)

Because hydrogen traps are key points to explain the crack initiation, the effect of hydrogen uptake is crucially relevant to the SSC phenomenon. The study of hydrogen in steels is often complicated because hydrogen is present in a variety of states. The lattice solubility of hydrogen (pH) depends on the external hydrogen pressure (P) and external hydrogen temperature (T), as shown in the following equation: pffiffiffiffiffi pH ¼ 0:00185 Pe


3400 T

(8.5)

Therefore, solubility of hydrogen pH increases with the increase of either hydrogen pressure or temperature. Also, with the increase of temperatures, the hydrogen diffusion coefficient increases (Moderer et al., 2013), whereas the solubility of H2S in water decreases. Moreover, the hydrogen-induced cracking sensitivity will decrease with the increase of pH, and thresholds of pH are studied under different conditions. As indicated earlier, tensile

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FIGURE 8.29

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Relationship between environmental pH and corrosion rate under H2S and/or CO2 condition.

stress is the other key factor contributing to the SSC effect. The stresses can be divided into two categories: load tensile stress and residual tensile stress. Usually, load tensile stress is not dangerous because design margin is properly provided, whereas residual tensile stress caused by welding process or cold work is more harmful. In this regard, since the 1970s, the effect of residual tensile stress on hydrogen diffusion through various steels has been extensively investigated, and some theoretical models have been proposed (Kim and Kim, 2014). When the tensile stress is higher, the time for crack will be generally shorter. Cold work results in an increase in both vacancy and dislocation densities, and therefore, higher hydrogen content of steel can be expected (Sourmail and Park, 2006). Interestingly, the presence of small concentration of H2S can have a significant effect on CO2 corrosion, and iron sulfide (FeS) can precipitate as the corrosion product in CO2/H2S environment, with various forms and different corrosion protectiveness. According to experiments, Fig. 8.29 shows the influence of pH in the H2S and CO2 environment on corrosion rate of carbon steel (Sridhar et al., 2006). Different rules of thumb have been used to determine how much H2S is required to turn a system from sweet to sour corrosion. The CO2/H2S ratio of 500 at 25 C is usually used to determine whether the corrosion product will be FeCO3 or FeS. For values > 500, the product will be FeCO3, and