Engineering Economy in Upstream Oil & Gas Field Development: A Concise Appraisal Technique for Investment Decision in Upstream Oil/Gas Projects 2759824888, 9782759824885

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ECO NOMY

M. Duan and M.D.U. Onuoha

Current Natural Sciences

Current Natural Sciences

E C O NO MY

Engineering Economy in Upstream Oil & Gas Field Development A Concise Appraisal Technique for Investment Decision in Upstream Oil/Gas Projects

The business of upstream oil and gas industry is a complex process that involves multidisciplinary participation. Producing crude oil and natural gas from the subsurface reservoir rocks to the point of the selling terminal requires stage by stage processes that costs several hundreds of millions of dollars to the operating companies. Because of the capital intensive nature of upstream investments, every required process is challenged of its economic impact or benefits it will have on the project’s net present value (NPV). The techniques applied in determining the economics of these processes and their selection criteria are addressed in the book. This book guides the reader through these strategic processes, and presents the participants involved in the business of upstream oil and gas prospecting and the conditions that dictate the field development and investment decisions by investors. It also reveals the shared interests and relationships that exist between international oil companies (IOCs) and national oil companies (NOCs) in the exploration and exploitation of their hydrocarbon resources and reserves. This text will serve the purpose of teaching and learning to those in the energy and financial sectors, as the methods, tools, and techniques discussed throughout the chapters will equip students, tutors, experts, and professionals with the necessary skills and knowledge of Exploration and Production (E&P) projects and energy financing and investment. The principles of project management as it applies in upstream oil/gas projects are discussed as well. And the criteria for project ranking, selection, and budgeting which are sine qua non to project financing and execution are well documented in this book.

ISBN : 978-2-7598-2488-5 www.edpsciences.org

Price: 112 €

Engineering Economy in Upstream Oil & Gas Field Development

Menglan DUAN and Mac Darlington Uche ONUOHA

Menglan DUAN and Mac Darlington Uche ONUOHA

Engineering Economy in Upstream Oil & Gas Field Development

ECO NOMY

M. Duan and M.D.U. Onuoha

Current Natural Sciences

Current Natural Sciences

E C O NO MY

Engineering Economy in Upstream Oil & Gas Field Development A Concise Appraisal Technique for Investment Decision in Upstream Oil/Gas Projects

The business of upstream oil and gas industry is a complex process that involves multidisciplinary participation. Producing crude oil and natural gas from the subsurface reservoir rocks to the point of the selling terminal requires stage by stage processes that costs several hundreds of millions of dollars to the operating companies. Because of the capital intensive nature of upstream investments, every required process is challenged of its economic impact or benefits it will have on the project’s net present value (NPV). The techniques applied in determining the economics of these processes and their selection criteria are addressed in the book. This book guides the reader through these strategic processes, and presents the participants involved in the business of upstream oil and gas prospecting and the conditions that dictate the field development and investment decisions by investors. It also reveals the shared interests and relationships that exist between international oil companies (IOCs) and national oil companies (NOCs) in the exploration and exploitation of their hydrocarbon resources and reserves. This text will serve the purpose of teaching and learning to those in the energy and financial sectors, as the methods, tools, and techniques discussed throughout the chapters will equip students, tutors, experts, and professionals with the necessary skills and knowledge of Exploration and Production (E&P) projects and energy financing and investment. The principles of project management as it applies in upstream oil/gas projects are discussed as well. And the criteria for project ranking, selection, and budgeting which are sine qua non to project financing and execution are well documented in this book.

ISBN : 978-2-7598-2488-5 www.edpsciences.org

Engineering Economy in Upstream Oil & Gas Field Development

Menglan DUAN and Mac Darlington Uche ONUOHA

Menglan DUAN and Mac Darlington Uche ONUOHA

Engineering Economy in Upstream Oil & Gas Field Development

Current Natural Sciences

Menglan DUAN and Mac Darlington Uche ONUOHA

Engineering Economy in Upstream Oil & Gas Field Development A Concise Appraisal Technique for Investment Decision in Upstream Oil/Gas Projects

Printed in France

EDP Sciences – ISBN(print): 978-2-7598-2488-5 – ISBN(ebook): 978-2-7598-2501-1 DOI: 10.1051/978-2-7598-2488-5 All rights relative to translation, adaptation and reproduction by any means whatsoever are reserved, worldwide. In accordance with the terms of paragraphs 2 and 3 of Article 41 of the French Act dated March 11, 1957, “copies or reproductions reserved strictly for private use and not intended for collective use” and, on the other hand, analyses and short quotations for example or illustrative purposes, are allowed. Otherwise, “any representation or reproduction – whether in full or in part – without the consent of the author or of his successors or assigns, is unlawful” (Article 40, paragraph 1). Any representation or reproduction, by any means whatsoever, will therefore be deemed an infringement of copyright punishable under Articles 425 and following of the French Penal Code. Ó Science Press, EDP Sciences, 2020

About the Authors

Menglan Duan College of Safety and Ocean Engineering, China University of Petroleum (Beijing), China Menglan Duan is the Dean of the College of Safety and Ocean Engineering, China University of Petroleum, Beijing, and a Professor of solid mechanics and ocean engineering. Professor Duan is an astute scholar with international reputation and has published over 400 technical papers including 104 SCI-indexed journal papers. He has covered a wide range of research areas and has conducted over 170 projects related to fixed and mobile platforms, subsea pipelines and risers, subsea production systems in Artic Mechanics and Offshore Engineering, Subsea Engineering, Fatigue and Failures of Materials and Structures, Dynamics of Offshore Engineering Structures, Mechanical Behaviour of Materials, and Risk and Reliability in Offshore and Ocean Engineering. His other areas of interest include management and economic analysis of oil/gas projects.

Mac Darlington Uche Onuoha College of Safety and Ocean Engineering, China University of Petroleum (Beijing), China Mac Darlington Uche Onuoha is an Assistant Professor of Solid/Fluid Mechanics and Offshore Oil & Gas Engineering at the College of Safety and Ocean Engineering, China University of Petroleum, Beijing. Dr. Onuoha is a young scholar with strong academic and research accomplishments. He has authored 7 publications in top international journals and conferences covering research areas such as, Flow Assurance in Deepwater Pipelines and Risers,

IV

About the Authors

Dynamics of Deepwater Riser Structures induced by Internal Severe Slug Loads, Multiphase Flow Simulation in Pipeline-Riser System, Finite Element Modeling and Analysis (FEM/FEA) of Offshore Structures, and Petroleum Economics and Feasibility Analysis of Upstream Investment. His research interest focuses on Fluid-Structure Interactions (FSI) of Subsea Production Systems, Dynamic Behaviour of Rigid & Flexible Risers, and Computational Fluid Dynamics of Multiphase Flows in Flowlines-Riser Pipe Systems.

Contents About the Authors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IX CHAPTER 1 Bidding and Petroleum Fiscal Instruments . . . . . 1.1 Concessionary License Agreement . . . . . . . . 1.2 Contractual Agreement . . . . . . . . . . . . . . . 1.2.1 Production Sharing Contract (PSC) 1.2.2 Service Contract . . . . . . . . . . . . . . . 1.2.3 Joint Venture Agreement . . . . . . . .

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Exploration & Reserve Estimation . . . . . . . . . . . . . . . . . . . . . 2.1 Discovered Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1.1 Basics of a Petroleum System . . . . . . . . . . . . . . . 2.1.2 Geophysical Methods for Oil & Gas Exploration . 2.1.3 Volumetric Estimation of Hydrocarbons in Place . 2.2 Recoverable Resources (Reserves) . . . . . . . . . . . . . . . . . . 2.2.1 Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . 2.2.2 Unproved Reserves . . . . . . . . . . . . . . . . . . . . . . .

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Appraisal and Field Development Planning . . . . . . . . . . . . . . . . . 3.1 Field Appraisal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Comprehensive Field Development Data . . . . . . . . . . . . . . 3.2.1 Geological and Reserve Data . . . . . . . . . . . . . . . . . . 3.2.2 Reservoir Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.3 Reservoir Simulation and Production Forecast . . . . 3.2.4 Drilling Program and Well Completion Design Plan 3.2.5 Production Period and Abandonment . . . . . . . . . . .

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CHAPTER 2

CHAPTER 3

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Contents

3.3 3.4 3.5

Technological Requirement & Challenges . . . . . . . . . . . . . . . . . . . . . . . 123 Safety and Environmental Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123 Production Operation, Workover, and Maintenance Plan . . . . . . . . . . . 124

CHAPTER 4 Economic Analysis of a Typical Upstream Development Project . 4.1 Basic Concepts in Economic and Financial Analysis . . . . . . 4.1.1 Economic Evaluation Indicators . . . . . . . . . . . . . . . 4.1.2 Cash Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . 4.1.3 Discounting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1.4 Time Value of Money and Economic Equivalence . . 4.1.5 Depreciation and Salvage Value . . . . . . . . . . . . . . . 4.1.6 Taxable Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 Case Study-Application of Economic Tools for Upstream Oil & Gas Project Evaluation . . . . . . . . . . . . . . . . . . . . . . 4.2.1 The Case Study (Data Presented Here Are not Real but Used for Exercise) . . . . . . . . . . . . . . . . . . . . . . .

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CHAPTER 5 Investment Decision and Project Selection 5.1 Capital Budgeting and Rationing . . . 5.2 Project Ranking . . . . . . . . . . . . . . . . 5.3 Comparison of Project Alternatives . 5.4 Inflation . . . . . . . . . . . . . . . . . . . . . .

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Project Management in Upstream Oil & Gas Field Development 6.1 An Overview of Project Management . . . . . . . . . . . . . . . . . 6.2 Process Groups in Project Management . . . . . . . . . . . . . . . 6.2.1 Project Initiating . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.2 Project Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.3 Project Executing . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2.4 Project Monitoring and Controlling . . . . . . . . . . . . 6.2.5 Project Closing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Work Breakdown Structure (WBS) . . . . . . . . . . . . . . . . . . 6.4 Design Proposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.5 Project Budgeting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.6 Project Risk Plan, Assessment, and Management . . . . . . . . 6.7 Role of Project Manager and Team Management . . . . . . . . 6.8 Project Quality Management . . . . . . . . . . . . . . . . . . . . . . .

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CHAPTER 6

Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 261 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265

Preface

The thought of writing this book came into our minds after discovering there are little resources that put together comprehensive and step-by-step procedures and techniques that are applied in the economic analysis of upstream oil/gas engineering projects. The subject addressed in this book is an important and indispensable topic in petroleum engineering, especially in the upstream sector which involves oilfield development and production planning. The core concept of this piece is not only meant for the petroleum sector but can also be extended to other sectors where a thorough economic evaluation is required to be carried out before any investment decision on a potential project commitment. Engineering Economy in Upstream Oil/Gas Field Development is a book that is selectively designed to serve the purpose of a teaching and learning material for courses in petroleum economics, energy finance, economic analysis, and little insight into project management. The book gives an account of all the scenarios and activities surrounding the business of oil and gas exploration and production in a given oil producing market. The chapters are presented in a sequential order that dictates the chronological stages involved between the national oil companies (NOCs) i.e. the host governments and the international oil companies (IOCs) during the process of license acquisition, exploration, and development of a leased oil block, in addition to project management and risk analysis. The synopsis of the methods, techniques, and theories covered in each of the chapters will also be discussed. Chapter 1 explains the legal proceedings followed by operators (i.e. IOCs) in oil-producing countries (i.e. Host governments) for the purpose of being awarded the exploration license of several acreage of oil blocks. This acquisition of rights comes in different terms depending upon the fiscal regime of the host government. Procedures to be followed in the event of oil discovery are also discussed in this chapter.

DOI: 10.1051/978-2-7598-2488-5.c901 © Science Press, EDP Sciences, 2020

VIII

Preface

Chapter 2 discusses the techniques and methods employed by exploration companies when searching for the black gold and the volumetric estimation of the recoverable quantities of oil (Reserves) in the event of a potential discovery of hydrocarbon deposits. Chapter 3 focuses on the positive outcome of oil exploration by providing technical details and other considerations put forward by prospective investors (Operating companies or IOCs) during planning and development phases of the discovered field, as the aim of the authors is to draw attention of readers to the stage by stage processes involved in the exploration and exploitation of petroleum resources by IOCs. Chapter 4 details the application of economic tools in evaluating the profitability and feasibility of a proposed project with a contextual analysis of an upstream field development case study. Chapter 5 dwells on whether there is any satisfactory outcome of the economic analysis performed on the proposed project which serves as an important input and valuable data that guide decision-makers in approving or disapproving the execution of the intended project for or against the interest of the company and its shareholders. It further discusses the concept of project ranking when comparing alternative investments that are independent, which helps investors to make a decisive choice in their project selection. Chapter 6 introduces slightly, the elements of project management as it relates to upstream field development projects with the view to enlighten the students on the multidimensional course of project management. Our objectives in producing this piece are to inculcate in the minds of our readers the ability and skills they would need in order to effectively conduct economic analysis and interpretation of results for their upstream and other related oil/gas engineering projects. The successful application of the knowledge gained in this book will require a strong background of the computational environment such as Excel, Matlab, Mathcad software and other well-structured programming languages in the likes of Visual Basics, Fortran 90, and C/C++. We have endeavoured to provide sufficient theories, methods, and techniques to help both the instructors and students in advancing the teachings and learning of this subject, and we do hope that this book will achieve the purpose and intentions of its authorship. Menglan Duan Mac Darlington Uche Onuoha

Acknowledgement

We sincerely express our profound gratitude to our families, colleagues, friends and experts who have in one way or the other successfully contributed towards the success of writing this book. Menglan Duan Mac Darlington Uche Onuoha

Chapter 1 Bidding and Petroleum Fiscal Instruments The Invitation to Bid The preliminary step an independent oil company will undertake in order to gain access for hydrocarbon exploration and exploitation in a given oil-producing country, normally designated as “the host government” is to build a favourable agreement with the host government, which starts by participating in a bidding process of an exploration acreage (i.e. oil block) expressed as a letter of intent by the host government. There are a lot of factors considered by International Oil Companies (IOCs) prior to their decision to participate in any bidding exercise. However, those factors will not be treated in this session but will be discussed extensively in chapter 4. By virtue of indigenization, the majority of the world’s hydrocarbon reserves are owned and controlled by the National Oil Companies (NOCs), such as NNPC (Nigeria), CNPC (China), ANPG (Angola), PETROBRAS (Brazil), PEMEX (Mexico), PETRONAS (Malaysia), and Saudi Aramco (Saudi Arabia) to mention but a few, which represent the relevant host governments and as such, requires them to develop and produce these petroleum resources for economic benefits. But in most cases, they lack the necessary technical expertise and financial strength to embark on such a complex project; hence, they usually sought for partnership with IOC. The government’s move to partner with third parties in developing their petroleum resources could come in the form of an open invitation to operators in the form of a licensing round of areas deemed to have potentials for petroleum accumulation which could be publicly announced in international media, business journals, technical magazines, etc., as a form of expression of interest to participate in the bidding of given oil blocks or be made by specific invitations to carefully selected operating majors for their participation.

DOI: 10.1051/978-2-7598-2488-5.c001 © Science Press, EDP Sciences, 2020

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Engineering Economy in Upstream Oil & Gas Field Development

Procedural Form of Bidding In the declared letters of intent, the government in question certifies its intent to award acreage of oil blocks to interested bidders with the provision of the geographic information of the said region (e.g. figure 1.1). The area of interest can be divided into a number of grid blocks whose sizes vary from one country to another. For example, Nigerian’s deepwater offshore OPL/OML license blocks are relatively sized 50  50 km (figures 1.2 and 1.3), US’s Gulf of Mexico blocks 3  3 miles, Norwegian’s blocks 20  20 km, UK’s North Sea 10  20 km, and deepwater Angola’s blocks 100  50 km (figure 1.4). The allotment of these blocks is done at the discretion of the government which usually goes in a progressive manner, like from shallower to deeper water areas as time changes. The government’s essence of offering an exploration opportunity in their oil blocks is to encourage investment from foreign investors, which invariably would provide economic rent should there be any successful discovery of hydrocarbon deposits from seismic survey and wildcat wells, in view of its development and production. In respect to the premise, the host government may ask for a signature bonus to be paid by bidders which forms part of the bid package. This is a lump sum

FIG. 1.1 – License map of Equatorial Guinea’s 2006 promotional blocks (sourced online).

Bidding and Petroleum Fiscal Instruments

3

FIG. 1.2 – Licensed OPL blocks deepwater offshore Nigeria (www.cp-africa.com).

FIG. 1.3 – Licensed OPL and OML blocks deepwater offshore Nigeria (www.energy-pedia.com).

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Engineering Economy in Upstream Oil & Gas Field Development

FIG. 1.4 – License blocks deepwater offshore Angola (sourced online). of cash payable by the successful bidder to the government on award of the blocks. A minimum value of signature bonus may be stipulated in the invitation to bid; however, this can as well be negotiated by the bidder. In the early phases of exploration of a basin, the government may reduce the amount of signature bonuses to tens of millions of dollars due to high risks of uncertainties. However, once initial discoveries are made in the area, it will attract an increased interest, and signature bonuses offered for subsequent nearby blocks could skyrocket to the tune of hundreds of millions of dollars. It is necessary to remind that this signature bonus is a sunk cost that is paid once, and should reflect as part of the capital cost of exploration and not subject to a tax-deductible cost against future earnings. Other relevant elements of the bid include the effective deadline and duration period for the exploration and scouting studies, the provisions for renewal if they exist and scope of the bidding which may require a minimum preliminary seismic data to be acquired with a minimum number of exploration wells, for example, a 3000 km of

Bidding and Petroleum Fiscal Instruments

5

2D/3D seismic data and 6/8 wildcat wells may be asked from each bidder. After the bidding is closed, the government or its representative NOC will open the submitted bids which could be done in public or more commonly behind closed doors. The winning bids may be publicized or kept confidential depending on the country’s modus operandi. The criteria by which bids are evaluated are usually a combination of signature bonus and the amount of preliminary data presented by each bidder which is graded on a weighted scale. The government decides which factor of the total bid package it attaches importance to i.e. the cash offered in signature bonus versus technical data, and would use it to choose in the case of a relatively close competitor. Furthermore, the government may put into consideration the technical competence, global reputation, any existing mutual relationships, and strategic policy the government may have enacted to encourage new entrants into the region. Finally, the details of the winning bids may be announced publicly and published in national and international dailies. This no doubt would be a useful information for subsequent bids and in comparison, will galvanize the strategy of other interested bidders. In another dimension, all the bids could be announced and the margin by which the winner emerged would be very clear. Though, the winner would hope not to have outbid the nearest competitor by a significantly large amount of money, to clear the mindset of not being overspent.

Contractors’ Participation to Bid As the competition for market share dominance grows among operating oil companies in increasing global energy demand, oil majors tend to increase their oil and gas reserves to meet this demand by investing offshore in other markets, and also to increase the company’s share value. This of course will be the driving force that will increase the willingness of any operating company to participate in any advertised licensing rounds of oil blocks in a given oil-producing country. But before such a decision is made, there are underlying factors to be considered by the company which involve the technical, economic, political, social and environmental aspect of the region under consideration. The technical aspect includes the potential size of hydrocarbons to be discovered and produced and technical challenges facing the accessibility and producibility of the hydrocarbon deposits, for example, in the case of extended reach and multilateral wells and offshore fields in ultra-deep waters. Economic and political implications include micro and macro-economic policies of the government, political stability, fiscal policy, potentials for nationalisation of the oil company’s assets, international embargoes and sanctions, taxation levels, restrictions on profit repatriation, security condition of personnel, local costs and standard of living, and local currency exchange rate and inflation predictions. The social factor will include any likely threat of civil disorder, the availability of local skilled and semi-skilled workers and any requirement for local training, and indigenous sense of accepting foreign investors. Local environmental laws and regulations designed to protect the environment from harmful activities are pictured as well by the company in ascertaining their compliance. Other considerations will be the reputational issue of doing business with a foreign government whose political

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Engineering Economy in Upstream Oil & Gas Field Development

and social norms fit within the values of the company’s government and its shareholders. On the advantageous ways of winning a bid, a lot may be required of the operating company than merely participating in a bidding process. Basically, operators who have interest in a particular market usually toe the path of the first building a mutual and working relationship with the government by having a small presence in the country from say, another business perspective, such as in downstream refining or distribution and sales. With that, the company will gain an extensive understanding of the local conditions and build strong relationship and cooperation with the key government departments, ministries and agencies such as the oil and gas ministry, department of petroleum resources, environmental and protection agency and local authorities. The spirit of this relationship and understanding of the local conditions may result in a direct agreement for participation in the bidding and the advantage can be leveraged. It may take a decade to build this understanding before tangible outcomes can be seen; however, the investment made during this period is considerable and can be viewed as laying the groundwork for prospective upstream interest.

Block Award The successful outcome of the bid will result in the award of the block by the host government thereby, giving the awardee the legal rights to explore the contractual area. With that, any signature bonus offered will be cashed-in by the government. As mentioned in the previous section, the scope of the exploration activities and timing enumerated in the invitation to bid by the government will dictate how the company will proceed in its scouting and for declaration of any commercial quantity of deposits if found. Normally, once a commercial quantity of hydrocarbon reserves is discovered, the company in question will like to progress beyond the exploration stage to appraisal and possibly, the development of the proven reserves. In this situation, the company will need to convert the exploration rights to development rights of the block. For example, in Nigeria, the Oil Prospecting License (OPL) given to operators for exploration purposes in the awarded block can be converted to Oil Mining Lease (OML) in the event of a commercially discovered oilfield.

1.1

Concessionary License Agreement

In the beginning of this section, we have spent a great deal of time discussing bidding and how the successful wining of a bid will grant the bidder, here, the international oil company, the rights to gain access to explore a block or group of blocks for any possible oil and gas accumulation. In the event a discovery of hydrocarbon deposits is made following several appraisals to determine the amount of proven reserves that can be recovered from these resources, the next thing will be the declaration of whether a commercial quantity was found or not. If not, it then means the block will be abandoned as it will

Bidding and Petroleum Fiscal Instruments

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not be economical to develop the field. However, we will assume the otherwise is the case where significantly large quantities of petroleum resources were found. Before the formal declaration of any found commercial quantity of hydrocarbons to the representative branch of the host government (NOC), the internal teams of the IOC will perform their preliminary analysis of the feasibility of developing the field and analyse whether the capital and operating expenses (CAPEX & OPEX) to be incurred could be offset at a recorded time within the production period of their contract and that would signal if a commercial quantity can be declared or not. This book is about all these processes and they have been detailed progressively in sequential order with the chapters and subsections. If the NOC is notified of this huge discovery after analyses have passed the expectations of the IOC, an entirely new and different agreement will be entered into by the two parties which will give IOC the rights to develop and produce the newfound oil/gas field. In most governments, the exploration rights will be converted to production rights with additional terms and conditions for producing the field in the new contract. For example, in Nigeria, the OPL license will be converted to OML lease after commercial quantity has been declared, and that will bring us to the objective of the forthcoming subsections where we will discuss several kinds of agreements entered into by the oil companies in order to produce the hydrocarbon resources from the field they have discovered after rigorous explorations and scouting studies. As the government prepares for the next phase of agreement for the development and production of the hydrocarbon reserves, which is one of the most important aspects of the field development project, the structure will determine how richer both sides could get from the deal. Depending on the government’s legal systems and fundamental laws, there exist two main kinds of Petroleum Agreement that can be entered into between NOC and IOC for the exploration, development and production of oil/gas reserves which are License Agreements and Contractual Agreements. The type adopted by any oil-producing country will depend on whether it follows an existing hydrocarbon law or comprehensive contractual agreements between NOCs and IOCs are used. Concessionary Agreement also known as Tax and Royalty Fiscal Regime, belongs to the license agreement where the government issues exclusive rights to ownership of the petroleum resources to the oil company while in return the state receives royalties and taxes in compensation for the production and sales of these resources by the operator. All the operations are wholly financed by the investor in this type of agreement and it bears all the risks associated thereof. The royalty is usually a percentage (≥10%) of the gross production of hydrocarbon and can be paid in cash or kind. It can be structured on a sliding scale depending on the production rate of the well, the terms of which may be negotiable on mutual fronts and understanding. Tax is paid after deductibles such as initial cost recovery, operating cost, depreciation, infill drilling cost, and royalty have been made. The taxable income can then be taxed based on the country’s corporate tax rate. Special investment incentive and tax relief programs may apply and tax losses can be carried forward to next year and beyond until full recovery is achieved.

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1.2

Engineering Economy in Upstream Oil & Gas Field Development

Contractual Agreement

In this type of agreement, the operating company secures the rights and privileges to an area through a contract with the host government or its representative national oil company. The stack difference between the contract agreement and the concessionary agreement is that, in the former, the ownership of the petroleum resources belongs to the state, i.e. the NOC. Here, the operator basically acts as a contractor to the host government and funds all operations or partly as in Joint Venture scenario. However, there is always a provision for the oil company to claim its capital cost and to receive a share of the profits either in cash or in kind. The forthcoming subsections will present different contractual fiscal regimes mostly practiced by the major oil-producing countries.

1.2.1

Production Sharing Contract

Production sharing contract (PSC) otherwise known as production sharing agreement (PSA) is one of the most populous contractual agreements widely used in over 40 countries, mostly the developing countries in Africa, Central Asia, South-East Asia, Middle East, and South America. It was first developed in Bolivia in the 1950s and was later introduced in Indonesia in 1966 to what we now know as Production Sharing Contract. Before its creation, concessionary or license regimes were the earlier fiscal instruments in use for petroleum agreements as can be found in developed countries like UK, Norway, the Netherlands, and Australia. The nature of this regime confers on the IOCs the proprietary rights of the contract area and complete ownership of any oil and gas found and produced thereof with subjection for payment of royalty and income tax. But it later got attacked by the rise of nationalist groups in the early 40s from which the PSC fiscal term was introduced to replace it. For example, after the Indonesian independence in 1945, the concessionary regime was attacked and eventually compelled the Indonesian government to stop granting new concessions which invariably caused a dip in foreign direct investment in Indonesia’s oil and gas sector. To curb these economic woes, the government enacted a new legislation that ushered in the production sharing agreement that is now widely adopted by many countries of the world such as in Nigeria, Angola, Malaysia, Brunei, Vietnam, Thailand, South Sudan just to mention but a few. Under a PSC contract term, the state or its representative NOC will contract with the IOC to provide the much needed technical skills and financial funding for the exploration and exploitation of hydrocarbons in a given area known as block, while the government retains its exclusive ownership of the contracted area and rights to the oil and gas reserves. By the sharing of the produced oil between the NOC and IOC in a well-structured and scaled manner, the operator (IOC) can carter for its cost recovery and profit entitlement whilst the government can generate foreign earnings through the sale of its share in the international market and for its domestic supply. There are numerous fiscal regimes PSCs that can be formulated, but they vary from country to country and the surrounding motives for which the given PSC contract term is designed for. For example, a government may design its PSC term

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to be more attractive to the investors by allocating more resources to the contractor’s share of the production when there are high risk and technological challenges in accessing the oil/gas deposits, or if there are domestic economic pressure and financial difficulties faced by the country where there is an urgent need for Foreign Direct Investment (FDI) to cushion all these problems. However, whichever is the case for which PSC contract is designed for, it will certainly contain the following four basic key elements:  Royalty: this is an initial condition put forward to IOC in which a royalty payment of an agreed per cent of the gross production to the state is expected. The royalty, at the government’s discretion, is often paid either “in kind” (i.e. a share of production) or “in cash” by an amount equivalent to the sale price of the state’s royalty share of the production.  Cost oil: after payment of royalty, the IOC is appropriated a certain per cent of the productions to enable it to recover its costs (with provisions for carrying forward to the next period, of any costs not fully recovered). The share quota is

FIG. 1.5 – Malaysia’s revenue over cost production sharing contract.

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TAB. 1.1 – Sliding scale of revenue-over cost production sharing contract (R/C PSC). Contractor’s R/C ratio 0:0\R=C  1:0 1:0\R=C  1:4 1:4\R=C  2:0 2:0\R=C  2:5 2:5\R=C  3:5 R=C  3:0

Cost oil

Profit oil

Cost oil ceiling

Unused cost oil Petronas

70% 60% 50% 30% 30% 30%

20% 30% 40% 50% 60%

: Contractor N.A. 80% 70% 60% 50% 40%

Profit oil Petronas 20% 30% 40% 50% 60% 70%

:

Contractor 80% 70% 60% 50% 40% 30%

FIG. 1.6 – Indonesia’s PSC model of 2006. scaled according to the production rate of the field and to which extent the costs have been recovered. This allocation is called cost oil.  Profit oil: the remaining of the gross production less royalty and cost oil is known as the profit oil. This is to be divided between the IOC and NOC in accordance

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with the terms and conditions of the production sharing provisions stipulated in the PSC contract. Figure 1.5 and table 1.1 show the Malaysian PSC term of 1988 and its sliding scale structure, while figure 1.6 shows the 2008 PSC terns of Indonesia.

1.2.2

Service Contract

Under this type of contract agreement, the NOC owns and operates the field while the IOC receives payments it charged for rendering technical services in exploring and developing the oil and gas reserves. This type of contract is usually adopted by states which have high propensity that the contracted area will show signs of hydrocarbon accumulation. Countries like Saudi Arabia, Iraq, Iran and Kuwait are known for using service contract in their petroleum agreement. In contrast to PSC contract, in service contract, the IOC has limited participation in the activities of the field. The mode of payment can either be in outright cash if the state has enough funds to offset all the monetary claims by the IOC or in-kind through production sharing. The service contract can come in two different forms which are:  Risk-free service contract: in this type of service contract, the uncertainties of not finding oil are minimal with little or no risk involved in the field development.  Risk-based service contract: as the name suggests, it is obvious to say in this type of contract there will be high risk involved in the exploration and development of the area. It is a 50–50 chance of success scenario of not finding and finding oil, where if the former takes the course, it would spell doom for the IOC as millions of dollars would be spent for nothing while the NOC will have nothing to lose. But if it goes the other way round, it would be a jackpot for the IOC because it will bill the state heavily for the high risks it had to go through in exploring and developing the area.

1.2.3

Joint Venture Agreement

In a joint venture (JV) agreement, the NOC and IOC jointly participate in the exploration and development of the resources, which means the state is obligated to contribute to the costs of developing and operating the field. The arrangement of JV may come in conjunction with either a PSC or a service contract. Most commonly, the participation interest in joint venture cooperation is split 51:49 in favour of the government. For example, in Nigeria’s NNPC/Chevron joint venture partnership the split is 60:40 in favour of the Nigerian National Petroleum Corporation (NNPC). Furthermore, the government may decide to participate as a contractor in the framework of PSC and bears all the exploration costs, and the contractor on the other hand will carry the state’s interest. In the event a commercial quantity is declared, the state can opt to convert its carried interest to full working participation while reimbursing the contractor for the costs it has incurred up to that point in operations and will be in proportion to the government’s acquired percent.

Chapter 2 Exploration & Reserve Estimation In chapter 1 we expended time talking about the legitimate procedures that are followed by IOCs in order to gain access to a foreign government’s hydrocarbon reserves for possible development and hydrocarbon production. Several kinds of petroleum fiscal instruments that serve as a legal document that protects the mutual interests of both NOC and IOC were deliberated as well. This chapter will take us through the engineering methods employed by IOC’s experts in tracing, evaluating, appraising, and finally estimating the volumetric quantity of the oil/gas resources found in the contracted block and how many of these quantities are recoverable or extractable after applying all the necessary recovery measures before the field’s reserve can be determined.

2.1

Discovered Resources

Expedition for search of oil/gas deposits requires multidisciplinary effort and relevant experts in geological sciences and petroleum engineering with the application of necessary tools and equipment. With the advent of advanced instrumentations and technological innovations, petroleum geologists and physicists can take advantage of these modern equipment and exploration techniques to have a better understanding of the history of the subsurface geology, its geophysical characteristics and improved exploration efficiency. However, they also ensure wildcat wells are precisely spudded for higher data accuracy and a greater possibility of success. Oil prospecting involves fieldwork and deployment of traditional survey tools such as gravity surveys, magnetic surveys, controlled sourced electro-magnetic (CSEM) surveys, and seismic surveys for acquisition of variations in geophysical properties of the Earth’s subsurface which includes the rocks (geology), fluids and voids with the ultimate goal of searching for the potential accumulation of hydrocarbons. Before going into the specificity of each of these geophysical methods, we would like to introduce what a petroleum system is and how its features are used by geophysicists and geologists for delineation of basins, location of boundaries for changes in properties and signal strength of the target area. DOI: 10.1051/978-2-7598-2488-5.c002 © Science Press, EDP Sciences, 2020

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2.1.1

Basics of a Petroleum System

A petroleum system consists of the following features:
Source rock: this is a sedimentary rock (figure 2.1) that contains sufficient amounts of organic matter (Plants & Animals) which when buried at a substantial depth of several kilometers and in the presence of high temperature and pressure, will produce petroleum. To preserve the organic remains from decomposition, the oxygen contents of the bottom waters and interstitial waters of the sediments need to be very low or even zero and sedimentation should occur at a rapid rate. Most source rocks are shale sediments which have low porosity and permeability and are primarily of marine origin. The conversion of sedimentary organic matter into petroleum after a series of thermal processes (decay, heat, pressure) is called maturation. This is believed to have happened in geologic time i.e. million years (figure 2.2) after which the organic-rich sediments were converted into layers of rocks following several stages in the generation of petroleum i.e. Diagenesis and formation of Kerogen; Catagenesis: formation of oil and wet gas; Metagenesis: dry gas formation. The quality and end products of the formed petroleum can be related to: Petroleum end product = ([Raw material + Accumulation + Transformation + Migration] + Geologic time). Figure 2.3 shows the thermal maturation processes of petroleum formation with emphasis on temperature increase with respect to depth known as geothermal gradient which is an important factor for maturation and hydrocarbon type and varies from basin to basin. An average value is around 3 °C per 100 m of the depth.
Reservoir rock: the rock plus void space contained in a trap and seal is called a reservoir (figure 2.4). Petroleum together with some water occurs in the pore spaces between the grains or crystals in the rock. Reservoir rocks are the most commonly coarse/fine-grained sandstones and carbonates (figure 2.5). However, the performance quality of a reservoir and its interaction with the flowing fluids will depend on the rock type, cementation of the sand grains or rock crystals, void density of the bulk volume (porosity) and connectivity level between these pores (permeability). The main chemical composition of sandstone reservoirs is Quartz (SiO2) (figure 2.6), which is a relatively stable mineral that does not change easily to variations in pressure, temperature, weather, or chemical reactions due to the acidity of reservoir pore fluids. They are formed after the weathered grains from the older rocks (Igneous and Metamorphic rocks) have been transported over large distances, rounded (figure 2.7), fined and sorted (figure 2.8), and finally deposited as sediments in a particular environment of deposition (onshore or offshore environment) to form what we generally classified as sedimentary rocks. On the other hand, carbonate reservoir rock is normally found in-situ at their place of formation. They are susceptible to changes in diagenetic processes i.e. all those physical and chemical alterations affecting sediments after deposition (figure 2.9). Figure 2.10 shows the relative chemical stability of carbonate minerals. With that said, the productivity index (PI) of any reservoir is basically a

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FIG. 2.1 – Typical petroleum system showing sediments of the source and reservoir rocks with seals, traps and faults geometries.

function of its porosity and permeability values. The measurement of void space in the rock reported either as a fraction ð0\x\1Þ or as a per cent ð0%\x\100%Þ of the bulk volume is called porosity (figure 2.11). This physical property determines the amount of hydrocarbons the reservoir rocks can contain and its behaviour is independent of the grain size but largely depends on packing (figure 2.12), sorting (figure 2.13), compaction and cementation (figure 2.9). Table 2.1 further itemizes the porosity ranges for different types of rock samples. Permeability, on the other hand, is a measure of the ease with which a formation permits a fluid to flow through it. To be permeable, a formation must have interconnected porosity (i.e. intergranular or intercrystalline porosity; interconnected vugs or fractures). To determine the permeability of a formation, several factors must be known: the size and shape of the formation, its fluid properties, the pressure exerted on the fluids and the amount of fluid flow. Figures 2.14 and 2.15 show the core sample’s experimental test and the theoretical models for analysing the permeability of a reservoir. The more the pressure is exerted on a fluid, the higher the flow rate. The permeabilities of average reservoir rocks generally range between 5 and 1000 md. A reservoir rock whose permeability is 5 md or less is called tight sand or a dense limestone depending on its composition. A rough appraisal of the field’s reservoir permeability is expressed below: Fair 1–10 md (millidarcys) Good 10–100 md (millidarcys) Very good 100–1000 md (millidarcys)

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FIG. 2.2 – Geological time-scale showing years of geological age and its associated organic sediments for petroleum generation and accumulation in the source rocks.

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FIG. 2.3 – Correlation between hydrocarbon generation, temperature and some pale-thermometers.

Permeability calculation can be expressed in different forms depending on the number of hydrocarbon fluids that flow commingly in the reservoir. Absolute Permeability ðKa Þ is calculated when there is only one fluid present in the pores of a formation. Effective Permeability ðKe Þ evaluates the ability of a rock to conduct one fluid in the presence of another by considering that both fluids are immiscible (e.g. oil and water). Effective permeability depends not only on the permeability of the rock itself but also on the relative amounts of the different types of fluid present. Relative Permeability ðKr Þ obtains the ratio of a fluid’s effective permeability to the formation’s absolute permeability (i.e. when is 100% saturated with that fluid). Relative permeability reflects the amount of a specific fluid that will flow at a given saturation in the presence of other fluids to the amount that would flow at saturation of 100%, with all other factors remaining the same. However, permeability depends upon the size, shapes and pore-throat diameter. Packing is dependent on depositional and diagenetic history.
Seals: these are fine-grained or crystalline, low permeability rocks. Typical examples include Mudstone/Shale, Cherts, Anhydrites and Salt (Halite). Seals to fluid flow can also develop along fault planes, faulted zones and fractures. The presence of seals is critical for the development of petroleum accumulations in the subsurface formation.

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FIG. 2.4 – A reservoir rock bounded by the impermeable source and seal rocks with edge faults, migration path and reservoir fluids (oil and water).

FIG. 2.5 – The carbonate and sandstone rock samples.

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FIG. 2.6 – Sand grains’ components of a sandstone reservoir showing the minerals, pore spaces, cement and rock matrix.
Traps: the geometry of the sealed petroleum-bearing rock. Mapping of trap geometry is a fundamental part of petroleum geoscience and there are three basic forms of trap which are anticlinal, fault and stratigraphic traps (figure 2.16). A broader cross-sectional view of the anticlinal trap is shown in figure 2.17.
Timing and migration: the timing of petroleum maturation, migration and trapping of oil did occur a few million years ago known as geologic time-scales as shown in figure 2.2. However, the maturation of source rocks situated in deeper and hotter parts of the large basin is consequently followed by the migration of the produced hydrocarbons into more suitable rock structures (reservoir). This is because oil and gas are lighter than water and are more prone to move upward through permeable strata. Basically, there are two recognised stages in the migration process: Firstly, the primary migration accounts for the process of Kerogen transformation into oil/gas that induces micro-fracturing of the impermeable and low porous source rock which then allows the hydrocarbons to move into more permeable strata, and the secondary migration wherein the produced fluids move more freely along the bedding planes and fault into the reservoir rocks at a considerable lateral distance of up to several tens of kilometers. Figures 2.1, 2.4, and 2.18 show a comprehensive description of a petroleum system with its different geometries owing to the tectonic movements of the earth’s plates and the resultant faults.

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Engineering Economy in Upstream Oil & Gas Field Development

FIG. 2.7 – The roundness and sphericity of clastic grains.

Now we have exhaustively introduced the key elements of a petroleum system, we shall then proceed with our earlier discussion on different geophysical methods and how they respond to variations in physical properties of a petroleum system when mapping for potential hydrocarbon accumulation. The forthcoming sections will discuss respectively, the exploration methods and how the discovered hydrocarbon deposits can be initially quantified.

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FIG. 2.8 – Sorting of transported sand grains during deposition and sedimentation processes.

FIG. 2.9 – Diagenetic processes showing the compaction and cementation of deposited sediments.

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Engineering Economy in Upstream Oil & Gas Field Development

FIG. 2.10 – Stability ranking of carbonates minerals.

FIG. 2.11 – Physical description of different porosity values.

2.1.2

Geophysical Methods for Oil & Gas Exploration

Magnetic Surveys Magnetic geophysical surveys measure small, localised variations in the earth’s magnetic field caused by changes in the magnetic properties of rocks. These changes

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FIG. 2.12 – Grain packing in sandstone ( modified from Blatt, 1982).

in naturally occurring materials such as magnetic ore bodies and basic igneous rocks allow them to be identified and mapped by magnetic surveys. If they are located close to the surface they give rise to anomalies with a short wavelength and high amplitude. Strong local magnetic fields or anomalies are also produced by buried steel objects. Magnetometer surveys could find underground storage tanks, drums, piles and reinforced concrete foundations by detecting the magnetic anomalies they produced. Anomalous magnetisation may be associated with local mineralization of commercial interest or on a global scale it can be associated with the earth’s magnetic field. The survey pattern is usually airborne (plane or satellite) as shown in figure 2.18 with flight flown at a constant elevation above sea level, spaced anywhere between 100 m to a few kilometers which ensures rapid surveying and mapping with good aerial coverage.

CSEM Seabed Surveys Controlled source electromagnetic (CSEM) surveying is a remote sensing technique that uses very low-frequency electro-magnetic signals emitted from a source near the seabed (figure 2.19). Receivers are placed on the seabed at regular intervals for registering anomalies and distortions in the electromagnetic signal generated by resistive bodies, such as reservoirs saturated with hydrocarbons.

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FIG. 2.13 – Sorting of sandstone grains during deposition (K. Simpson, 1995).

TAB. 2.1 – Pore space properties of different rock grains and crystals. Rock type Sand and gravel Till Silt Clay Clastic sediments Limestone Basalt Tuff Pumice Fractured crystalline rock Unfractured crystalline rock

Porosity ranges (%) 20–50 10–20 35–50 33–60 3–30