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Risk Assessment and

Mitigation strategies

for ‘Off shore drilling’

& 'Up-stream

activities' in the Oil &

Gas sector. Semester IV Research Project

Exploration and production of oil and natural gas requires high levels of capital

expenditure and entails particular economic risks. It is subject to natural

hazards and other uncertainties including those relating to the physical

characteristics of oil or natural gas fields. Exploratory activity involves

numerous risks including the risk of dry holes or failure to find commercial

quantities of hydrocarbons.

2013

ANURAG RAYCHAUDHURY, NITHIN SANTHOSH

SCMHRD, Pune

2/25/2013

Risk Assessment and Mitigation strategies for ‘Off shore drilling’ & 'Up-

stream activities' in the Oil & Gas sector.

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Table of Contents Acknowledgement .................................................................................................................................. 8

Certificate ................................................................................................................................................ 9

Executive Summary ............................................................................................................................... 10

Chapter 1 ............................................................................................................................................... 11

Risk Measurement ................................................................................................................................ 11

1.0 Introduction ................................................................................................................................ 11

1.1 Risk Analysis: Exploration ............................................................................................................ 12

1.2 Risk Analysis: Field Appraisal and Development......................................................................... 14

1.3 Decision Making Process, Value of Information and Flexibility .................................................. 15

1.4 Off shore Drilling Risks ............................................................................................................... 16

1.4.1 Seismic Surveys ........................................................................................................................ 16

1.4.2 Contaminated Drilling Discharges ............................................................................................ 17

1.4.3 Oil Spills .................................................................................................................................... 18

1.4.4 Impacts from Oil and Gas Infrastructure ................................................................................. 18

1.4.5 Money and Political Influence ................................................................................................. 19

1.4.6 Ecological Impact ..................................................................................................................... 19

1.4.7 Effect on Tourism ..................................................................................................................... 19

1.4.8 Risk to Workers ........................................................................................................................ 20

Chapter 2 ............................................................................................................................................... 21

Off-Shore Drilling .................................................................................................................................. 21

2.0 Where Did Offshore Drilling Originate? ...................................................................................... 21

2.1 Time Frame ................................................................................................................................. 21

2.2 Function ...................................................................................................................................... 21

2.3 Size .............................................................................................................................................. 21

2.4 Significance ................................................................................................................................. 21

2.5 Irony ............................................................................................................................................ 21

2.6 Off shore Drilling Ban History ..................................................................................................... 22

2.6.1 Legal Aspects ............................................................................................................................ 22

2.6.2 Early Events ............................................................................................................................. 22

2.6.3 Significance .............................................................................................................................. 22

2.6.4 Considerations .......................................................................................................................... 23

Chapter 3 ............................................................................................................................................... 24

Types of Offshore Drilling ..................................................................................................................... 24



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3.0 Introduction ................................................................................................................................ 24

3.1 Site Selection ............................................................................................................................... 24

3.2 Drilling Rigs .................................................................................................................................. 24

3.3 Test Wells .................................................................................................................................... 24

3.4 Drilling Platforms ........................................................................................................................ 24

3.5 Controversy ................................................................................................................................. 25

3.6 How Offshore Oil Drilling Works ................................................................................................. 25

3.6.1 Rigs ........................................................................................................................................... 25

3.6.2 Set Up ....................................................................................................................................... 25

3.6.3 Testing ...................................................................................................................................... 25

3.6.4 Extracting ................................................................................................................................. 26

3.7 Offshore Drilling Rig Types .......................................................................................................... 26

3.7.1 Submersible Oil Rigs ................................................................................................................. 26

3.7.2 Drillships ................................................................................................................................... 26

3.7.3 Semi-Submersible Oil Rigs ....................................................................................................... 26

3.7.4 Jack-Up Oil Rigs ........................................................................................................................ 26

3.7.5 Production Platforms ............................................................................................................... 27

3.8 Offshore Drilling Tools ................................................................................................................ 27

3.8.1 Drilling Rig ................................................................................................................................ 27

3.8.2 Production Platform ................................................................................................................. 27

3.8.3 Drills and Pipe .......................................................................................................................... 27

3.8.4 Drilling Fluid ............................................................................................................................. 28

3.8.5 Water Separators ..................................................................................................................... 28

3.9 Offshore Drilling Techniques ....................................................................................................... 28

3.9.1 Straight Hole Drilling ................................................................................................................ 28

3.9.2 Directional and Horizontal Drilling ........................................................................................... 28

3.9.3 Rotary Drilling .......................................................................................................................... 29

3.10 Offshore Drilling Dangers .......................................................................................................... 29

3.10.1 Personnel Mistakes and Equipment Failure .......................................................................... 29

3.10.2 Operational Malfunctions ...................................................................................................... 29

3.10.3 Natural Phenomenon ............................................................................................................. 30

3.10.4 Safety ..................................................................................................................................... 30

3.10.5 Offshore Drilling Dangers ....................................................................................................... 30



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Chapter 4 ............................................................................................................................................... 31

Pros & Cons of Offshore Oil Drilling ...................................................................................................... 31

4.1 Benefits of Offshore Drilling ........................................................................................................ 32

4.1.2 Domestic Fuel........................................................................................................................... 32

4.1.3 Environment............................................................................................................................. 32

4.2 Bad Effects of Offshore Drilling ................................................................................................... 32

4.2.1 Environmental Disadvantages ................................................................................................. 33

4.2.2 Environmental Effects of Platforms ......................................................................................... 33

4.2.3 Practical Difficulties and Risks .................................................................................................. 33

4.3 Weighing the Benefits & Costs of Offshore Drilling .................................................................... 33

4.4 Modelling Oil Spill Response And Damage Costs ........................................................................ 36

4.4.1 Introduction ............................................................................................................................. 36

4.4.2 Methodology ............................................................................................................................ 37

4.4.3 Results ...................................................................................................................................... 38

4.4.4 Discussion................................................................................................................................. 39

Chapter 5 ............................................................................................................................................... 47

Technical Risks ...................................................................................................................................... 47

5.0 Risks of Offshore Oil Drilling: ...................................................................................................... 47

5.0.1. Introduction ............................................................................................................................ 47

5.0.2 Evolution of Oil Drilling in the US ............................................................................................. 48

5.0.3 Basic Knowledge of Deep Water Oil and Gas Prospection and Drilling Techniques ............... 49

5.0.4 The Macondo Oil Rig Explosion: Course and Causes ............................................................... 51

5.0.5 Assessment of the Socio-economic Impacts of the Oil Spill .................................................... 55

5.0.6 Health Vulnerabilities of the Oil Spill ....................................................................................... 56

5.0.7 Environmental Impacts of Oil Spill ........................................................................................... 57

5.0.8. Management of the Impact of the Oil Spill ............................................................................. 59

5.0.9 Claims and Contingency Plans ................................................................................................. 61

5.0.10. Conclusion ............................................................................................................................. 61

5.0.11. Recommendations ................................................................................................................ 62

5.1 Drilling and Well Risk Assessment .............................................................................................. 63

5.1.1 The Nature of the Risk ............................................................................................................. 63

5.1.2 Operation ................................................................................................................................. 64

5.1.3 Challenge .................................................................................................................................. 64



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5.1.4 Details ...................................................................................................................................... 64

5.1.5 Results ...................................................................................................................................... 65

Chapter 6 ............................................................................................................................................... 66

Financial and Other Risks ...................................................................................................................... 66

6.1 Offshore oil and gas operations .................................................................................................. 66

6.1.1 Major hazards report and major accident policy ..................................................................... 66

6.1.2 Internal and external emergency response plans ................................................................... 66

6.1.3 Need for a directive ................................................................................................................. 67

6.1.4 Application and transposition .................................................................................................. 67

6.1.5 Follow Up ................................................................................................................................. 67

6.2 Stricter Rules ............................................................................................................................... 67

6.2.1 Liability ..................................................................................................................................... 67

6.2.2 Emergency Response Plans ...................................................................................................... 68

6.2.3 Jurisdiction ............................................................................................................................... 68

6.2.4 Reactions .................................................................................................................................. 68

6.3 Oil Spill Risk Management For Offshore Exploration And Production Oil Platforms: ................ 69

6.3.1 Introduction ............................................................................................................................. 69

6.3.2 Analysis .................................................................................................................................... 69

6.3.3 Discussion, Conclusions and Implications ................................................................................ 70

6.3.4 Recommendations ................................................................................................................... 71

Chapter 7 ............................................................................................................................................... 73

The Indian Scenario ............................................................................................................................... 73

7.1 India's Unfavourable Climate in Oil & Gas .................................................................................. 73

7.2 Exploration Risk Management in Indian PSUs ............................................................................ 74

7.2.1 Introduction ............................................................................................................................. 74

7.2.2 Project Setting .......................................................................................................................... 75

7.2.3 Objectives of Risk Assessment Study ....................................................................................... 75

7.2.4 Scope of Work .......................................................................................................................... 75

7.2.5 Drilling Process ......................................................................................................................... 76

7.2.6 Exploration Plan for MN-ONN-2000/1 Block ........................................................................... 76

7.2.7 Maximum Credible Accident Analysis ...................................................................................... 77

7.2.8 Consequence Analysis .............................................................................................................. 77

7.2.9 Results and Discussions ........................................................................................................... 77



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7.2.9.1 Consequence Analysis of Wells ......................................................................................... 77

7.2.9.2 Well Blowout ..................................................................................................................... 77

7.2.10 Risk Mitigation Measures....................................................................................................... 77

7.2.10.1 Risks to Personnel ........................................................................................................... 77

7.2.11 Specific Recommendations .................................................................................................... 78

7.2.11.1 Wells................................................................................................................................ 78

7.2.12 Disaster Management Plan .................................................................................................... 78

7.2.13 Objectives of Disaster Management Plan .............................................................................. 78

7.2.14 Disaster Management Plan .................................................................................................... 78

7.2.15 Approach to Disaster Management Plan ............................................................................... 79

7.3 Unconventional risks ................................................................................................................... 79

7.3.1 Implications .............................................................................................................................. 80

7.3.2 Environmental issues ............................................................................................................... 81

7.3.3 Implications .............................................................................................................................. 82

7.4 Issues in oil exploration............................................................................................................... 83

7.4.1 Dispute Areas ........................................................................................................................... 83

Chapter 8 ............................................................................................................................................... 86

Pipeline Protection- New Age Technologies ......................................................................................... 86

8.1 Secure Pipe .................................................................................................................................. 86

8.1.1 Applications.............................................................................................................................. 86

8.1.2 Specifications ........................................................................................................................... 87

8.1.3 Installation Overview ............................................................................................................... 87

8.1.4 Case Studies ............................................................................................................................. 87

8.1.5 How it Works ............................................................................................................................ 89

8.2 Acoustic Fibre Optic Pipeline Security System ............................................................................ 89

8.2.1 Land Based Systems ................................................................................................................. 90

8.2.2 Sub-Aqua Systems .................................................................................................................... 90

8.2.3 Intruder & Third Party Interference (TPI) Detection ................................................................ 90

8.2.3.1 Acoustic Fibre Optic Pipeline Security System .................................................................. 90

8.2.3.2 Unrivalled Acoustic Surveillance for any Length of Pipeline in any Situation................... 92

8.2.3.3 Monitor, Identify and Alert; Minimise False Alarms ......................................................... 92

8.2.3.4 Simple and Rapid Installation ........................................................................................... 93

8.2.3.5 High Resilience, Intrinsically Safe and Low Maintenance ................................................. 93



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8.2.3.6 AFOPSS Delivery ................................................................................................................ 93

8.2.3.7 AFOPSS - Key Advantages ................................................................................................. 93

8.2.3.8 Sensing System Technical Specifications .......................................................................... 94

8.2.3.9 Operation .......................................................................................................................... 94

8.2.3.10 Graphical User Interface ................................................................................................. 95

8.2.3.11 PIG Monitoring ................................................................................................................ 95

8.2.3.12 Leak Detection ................................................................................................................ 95

8.2.3.13 Perimeter Intruder Detection ......................................................................................... 95

8.2.4 Westminster Dual Purpose Pipeline Security and Leak Detection System .............................. 96

Chapter 9 ............................................................................................................................................... 97

Conclusion ............................................................................................................................................. 97

9.1 Strategies for Exploration ........................................................................................................... 97

9.2 Post-2000 .................................................................................................................................... 98

9.3 M&A/Capex shift ......................................................................................................................... 99

9.4 Deepwater Situation ................................................................................................................. 100

9.5 Last Steps .................................................................................................................................. 101

References .......................................................................................................................................... 106

Appendix

Appendix 1............................................................... Impacts of Seismic Surveys

Appendix 2............................................................... Contaminated Discharges from OCS Operations

Appendix 3................................................................ Installation Overview Pipe

Appendix 4...................................................... ..........How it Works the Pipe



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Acknowledgement

We, Anurag Raychaudhury and Nithin Santhosh, students of MBA-Infrastructure Management, SCMHRD, Pune, thank Dr. Ajit Patwardhan, Faculty, CoE Infrastructure management, SCMHRD, Pune and Professor Pavan Totla, external faculty, SCMHRD, Pune, for their support and guidance provided throughout this thesis work. Without such help, this project would not have been completed on time. We also thank our colleagues who provided us with various inputs from their end which helped us in collection of data and analyzing the problems and provide possible solutions to them. Last but not the least; we thank our Director K.S Subramanian, for giving us the opportunity to do this project as part of our semester four research project.



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Certificate

This is to certify that Nithin Santhosh, roll number 2011E11 and Anurag Raychaudhury, roll number 2011E14, of MBA-Infrastructure Management, Symbiosis Centre for Management and Human Resource Development, have completed their thesis work on “Risk Assessment

and Mitigation strategies for ‘Off shore drilling’ & 'Up-stream activities' in the Oil &

Gas sector.” satisfactorily.

Dr Ajit Patwardhan Faculty- CoE Infrastructure Management

SCMHRD, Pune



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Executive Summary

Exploration and production of oil and natural gas requires high levels of capital expenditure and entails particular economic risks. It is subject to natural hazards and other uncertainties including those relating to the physical characteristics of oil or natural gas fields. Exploratory activity involves numerous risks including the risk of dry holes or failure to find commercial quantities of hydrocarbons.

There is a long sequence of many processing steps required before the fuel flows through the hose. At the beginning of it all there is the crude oil that is produced at a great expense – a process placing the highest demands on personnel and equipment: scorching heat under the desert sun, the harsh climate of the North Sea or arctic temperatures, noise, dirt, bad smells, a permanent danger of explosion due to flying sparks and hazards related to drilling through rock. These are only some factors that determine work at production plants and platforms onshore and offshore, below and above the water. The same harsh conditions apply during the extraction of gas, before it is dried, cleaned, conditioned and processed then delivered via pipeline for use. The result: cozy rooms in wintertime and hot water.

Such extreme operating conditions require special safety standards in order to meet all demands and comply with all requirements. It is essential that the technologies used meet the highest quality standards in order to ensure the self-sufficient and stand-alone 24-hour operation of production plants and platforms. Nothing but the best equipment should be good enough. These equipments should be adaptable to most of the possible hazards and must stand out in its durability, toughness and its reliable and safe operation.

Developing and marketing hydrocarbons reserves typically requires several years after a discovery is made. This is because a development project involves an array of complex and lengthy activities, including appraising a discovery in order to evaluate its commerciality, sanctioning a development project and building and commissioning relating facilities. As a consequence, rates of return of such long- lead-time projects are exposed to the volatility of oil and gas prices and the risk of an increase in developing and lifting costs, resulting in lower rates of return. This set of circumstances is particularly important to those projects intended to develop reserves located in deep water and harsh environments, where the majority of the projects are planned and ongoing projects are located.

In this paper we have tried to assess these issues as well as provided some solutions which are currently available and used globally. We have also tried to analyze the Indian scenario of risk management and tried to see if these globally accepted systems are worthwhile trying in India as of now. Finally some recommendations are provided to mitigate these risks.

Also an additional section discusses the best pipeline monitoring systems available for the Up and Mid stream sector of the Oil and Gas Industry.



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Chapter 1

Risk Measurement

1.0 Introduction

Exploration and production of hydrocarbons is a high-risk venture. Geological concepts are uncertain with respect to structure, reservoir seal, and hydrocarbon charge. On the other hand, economic evaluations have uncertainties related to costs, probability of finding and producing economically viable reservoirs, technology and oil price.

Even at the development and production stage the engineering parameters embody a high level of uncertainties in relation to their critical variables (infrastructure, production schedule, quality of oil, operational costs, reservoir characteristics etc.).

These uncertainties originated from geological models and coupled with economic and engineering models involve high-risk decision scenarios, with no guarantee of successfully discovering and developing hydrocarbons resources.

Corporate managers continuously face important decisions regarding the allocation of scarce resources among investments that are characterized by substantial geological and financial risk.

For instance, in the petroleum industry, managers are increasingly using decision analysis techniques to aid in making these decisions. In this sense, the petroleum industry is a classic case of uncertainty in decision-making; it provides an ideal setting for the investigation of corporate risk behavior and its effects on the firm’s performance. The wildcat drilling decision has long been a typical example of the application of decision analysis in classical textbooks.

Future trends in oil resource availability will depend largely on the balance between the outcome of the cost-increasing effects of depletion and the cost-reducing effects of new technology. Based upon that scenario, new forms of reservoir exploitation and management will appear where the contributions of risk and decision models are one of the important ingredients. This trend can be seen in the last two decades. The new internationally focused exploration and production trategies were driven in part by rapidly evolving new technologies. Technological advances allowed exploration in well-established basins as well as in new frontier zones such as ultra-deep water.

Those technology-driven international exploration and production strategies combined with new and unique strategic elements where risk analysis and decision models represent important components of a series of investment decisions.



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1.1 Risk Analysis: Exploration

The historical origins of decision analysis can be partially traced to mathematical studies of probabilities in the 17th and 18th centuries by Pascal, Laplace, and Bernoulli. However, the applications of these concepts in business and general management appeared only after the Second World War (Covello and Mumpower, 1985; Bernstein, 1996). The problem involving decision-making when there are conditions of risk and uncertainty has been notorious since the beginnings of the oil industry. Early attempts to define risk were informal. The study by Allais (1956) on the economic feasibility of exploring the Algerian Sahara is a classic example because it is the first study in which the economics and risk of exploration were formally analyzed through the use of the probability theory and an explicit modelling of the sequential stages of exploration. Allais was a French economist who was awarded the Nobel Prize in Economics in 1988 for his development of principles to guide efficient pricing and resource allocation in large monopolistic enterprises. Allais’ work was a useful means or preview to demonstrate Monte Carlo methods of computer simulation and how they might be used to perform complex probability analysis, instead of simplifications of risk estimation of large areas. During this period, there were several attempts to define resource level probabilities at various stages of exploration in a basin using resource distribution and risk analysis (Kaufman, 1963; Krumbein and Graybill, 1965; Drew, 1967; Harbaugh et al., 1977; Harris, 1984; Harbaugh, 1984, Harris 1990). At that time governmental agencies (U.S. Geological Survey, Institut Français du Pétrole, etc.) were also beginning to employ risk analysis in periodic appraisals of oil and gas resources (Figure 1). During the 1980’s and 1990’s, new statistical methods were applied using several risk estimation techniques such as: (1) lognormal risk resource distribution (Attanasi and Drew, 1985), (2) Pareto distribution applied to petroleum field-size data in a play (Crovelli, 1995) and (3) fractal normal percentage (Crovelli et al., 1997). Recently, USGS has developed several mathematical models for undiscovered petroleum resource assessment (Ahlbrandt and Klett, 2005) and forecast reserve growth of fields both in the United States (U.S.) and the world (Klett, 2005). Throughout 1960’s, the concepts of risk analysis methods were more restricted to academia and were quite new to the petroleum industry when contributions appeared from Grayson (1960), Arps and Arps (1974), Newendorp (1975, edited as Newendorp and Schuyler, 2000) and Megill (1977). Newendorp (op.cit.) emphasized that decision analysis does not eliminate or reduce risk and will not replace professional judgment of geoscientists, engineers, and managers. Thus, one objective of decision analysis methods, as will be discussed later in this paper, is to provide a strategy to minimize the exposure of petroleum projects to risk and uncertainty in petroleum exploration ventures. The assessment to risk model preferences of decision makers can be achieved using a utility function provided by Utility Theory. If companies make their decisions rationally and consistently, then their implied risk behaviors can be described by the parameters of



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a utility function. Despite Bernoulli’s attempt in the 18th century to quantify an individual’s financial preferences, the parameters of the utility function were formalized only 300 hundred years later by von Neumann and Morgenstern (1953) in modern Utility Theory. This seminal work resulted in a theory specifying how rational individuals should make decisions in uncertain conditions. The theory includes a set of axioms of rationality that form the theoretical basis of decision analysis. Descriptions of this full set of axioms and detailed explanations of decision theory are found in Savage (1954), Pratt (1964), and Schailfer (1969). Cozzolino (1977) used an exponential utility function in petroleum exploration to express the certainty equivalent that is equal to the expected value minus a risk discount, known as the risk premium. Acceptance of the exponential form of risk aversion leads to the characterization of risk preference (risk aversion coefficient), which measures the curvature of the utility function. Lerche and MacKay (1999) showed a more comprehensible form of risk tolerance that could intuitively be seen as the threshold value, whose anticipated loss is unacceptable to the decision maker or to the corporation. An important contribution that provides rich insight into the effects of integrating corporate objectives and risk policy into the investment choices was made by Walls (1995) for oil and gas companies using the multi-attribute utility methodology (MAUT). Walls and Dyer (1996) employed the MAUT approach to investigate changes in corporate risk propensity with respect to changes in firm size in the petroleum industry. Nepomuceno Fo et al. (1999) and Suslick and Furtado (2001) applied the MAUT models to measure technological progress, environmental constraints as well as financial performance associated with exploration and production projects located in offshore deep waters. More recently, several contributions devise petroleum exploration consisting of a series of investment decisions on whether to acquire additional technical data or additional petroleum assets (Rose, 1987). Based upon these premises exploration could be seen as a series of investment decisions made under decreasing uncertainty where every exploration decision involves considerations of both risk and uncertainty (Rose, 1992). These aspects lead to a substantial variation in what is meant by risk and uncertainty. Some authors such as Knight (1921) make a distinction between risk (where probabilities are known) and uncertainty (where one is unable to assign probabilities) focusing their analysis on uncertainty. Meanwhile, Megil (1977) considered risk an opportunity for loss. Risk considerations involve size of investment with regard to budget, potential gain or loss, and probability of outcome. Uncertainty refers to the range of probabilities in which some conditions may exist or occur. Rose (2001) pointed out that each decision should allow a progressively clearer perception of project risk and exploration performance that can be improved through a constructive analysis of geotechnical predictions, review of exploration tactics versus declared strategy, and year-to-year comparison of exploration performance parameters. These findings showed the importance of assessing the risk behaviour of firms and managerial risk attitudes.



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Continued monitoring of the firm’s level of risk aversion is necessary due to the changing corporate and industry environment as well as the enormous contribution generated by technological development in E&P. Over any given budgetary period, utilization of an established risk aversion level will result in consistent and improved decision making with respect to risk.

1.2 Risk Analysis: Field Appraisal and Development

During the exploration phase, major uncertainties are related to volumes in place and economics.

As the level of information increases, these uncertainties are mitigated and, consequently, the importance of the uncertainties related to technology and recovery factor increases. The situation is more critical in offshore fields and for heavy-oil reservoirs, where investments are higher and there is a lower operational flexibility.

In the preparation of development plans, field management decisions are complex issues because of (1) the number and type of decisions, (2) the great effort required to predict production with the necessary accuracy and (3) the dependency of production strategy definition on several types of uncertainty with significant impact on risk quantification.

In order to avoid excessive computation effort, some simplifications are always necessary. The key point is to define the simplifications and assumptions that can be made to improve performance without significant precision loss. Simplifications are possible, for instance, in the modelling tool, treatment of attributes and in the way several types of uncertainties are integrated.

One of the simplest approaches is to work with the recovery factor (RF) that can be obtained from analytical procedures, empirical correlations or previous simulation runs, as presented by Salomão and Grell (2001). When higher precision is necessary, or when the rate of recovery significantly affects the economic evaluation of the field, using only the expected recovery factor may not be sufficient.

The integration of risk analysis into the definition of production strategy can also be very time consuming because several alternatives are possible and restrictions have to be considered. Alternatives may vary significantly according to the possible scenarios. Schiozer et al. (2004) proposed an approach to integrate geological and economic uncertainties with production strategy using geological representative models to avoid large computational effort.

Integration is necessary in order to (1) quantify the impact of decisions on the risk of the projects, (2) calculate the value of information, as proposed by Demirmen (2001) and (3) quantify the value of flexibility (Begg and Bratvold, 2002; Hayashi et al.,



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2007). The understanding of these concepts is important to correctly investigate the best way to perform risk mitigation and to add value to E&P projects.

Therefore, risk analysis applied to the appraisal and development phase is a complex issue and it is no longer sufficient to quantify risk. Techniques today are pointing to: (1) quantification of value of information and flexibility, (2) optimization of production under uncertainty, (3) mitigation of risk and (4) treatment of risk as an opportunity. All these issues are becoming possible due to hardware and software advances, allowing an increasing number of simulation runs of reservoir models with higher complexity.

1.3 Decision Making Process, Value of Information and Flexibility

Making important decisions in the petroleum industry requires incorporation of major uncertainties, long time horizons, multiple alternatives, and complex value issues into the decision model. Decision analysis can be defined on different and embedded levels in petroleum exploration and production stages. Raiffa (1968) and Keeney (1982) defined decision analysis as a philosophy, articulated by a set of logical axioms, and a methodology and collection of systematic procedures, based upon those axioms, for responsibly analyzing the complexities inherent in decision problems. Several textbooks can be found in Raiffa, 1968; Keeney, 1982; Keeney and Raifa, 1976; Howard, 1988; Kirkwood, 1996, and Clemen, 1990. In the last two decades, the theoretical and methodological literature on various aspects of decision analysis has grown substantially in many areas of petroleum sector, especially in applications involving health, safety, and environmental risk. Many complex E&P decision problems involve multiple conflicting objectives. Under these circumstances, managers have a growing need to employ improved and systematic decision processes that explicitly embody the firm’s objectives, desired goals, and resource constraints. Over the last two decades, the advances in computer-aided decision making processes have provided a mechanism to improve the quality of decision making in the modern petroleum industry. Walls (1996) developed a decision support model that combines toolbox system components to provide a comprehensive approach to petroleum exploration planning from geological development through the capital allocation process. An effective way to express uncertainty is to formulate a range of values, with confidence levels assigned to numbers comprising the range. Although geoscientists and engineers may be willing to make predictions about unknown E&P situations, there is a need to assess the level of uncertainty of the projects. So, it’s necessary to define the value of information associated with important decisions such as deferring drilling of a geologic prospect or seismic survey. Information only has value in a decision problem if it results in a change in some action to be taken by a decision maker. Furthermore, this change must bring an expected benefit greater than the cost of information. The information is seldom perfectly reliable and generally it does not eliminate uncertainty, so the value of information depends on both the amount of uncertainty (or



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the prior knowledge available) and payoffs involved in E&P projects. The value of information can be determined and compared to its actual cost and the natural path to evaluate the incorporation of this new data is by Bayesian analysis. As the level of information increases, the decision making process becomes more complex because of the need for (1) more accurate prediction of field performance and (2) integration with production strategy. At this point, the concept of Value of Information (VoI) must be integrated with the Value of Flexibility (VoF) as shown by Hayashi et al. (2007). Therefore, risk may be mitigated by more information or flexibility in the production strategy definition. Reservoir development by stages and smart wells are good examples of investments in flexibility. The decision to invest in information or flexibility is becoming easier as more robust methodologies to quantify VoI and VoF are developed.

1.4 Off shore Drilling Risks

Offshore oil and gas exploration and development poses a number of risks and potential

impacts to marine life, including:

• Harm to fish, crab and marine mammals caused by seismic surveys.

• Contamination of fish and pollution of marine waters caused by drilling operations.

• Oil spills from platforms, underwater pipelines and/or tankers.

• Interference with commercial and subsistence fishing activities.

1.4.1 Seismic Surveys

Marine seismic surveys are used to help determine the location of oil and gas deposits

beneath the seafloor. Seismic surveys use large ships towing powerful air guns that generate

sound waves by firing off explosive blasts of air. The sound waves are reflected off the

seafloor creating a picture of underwater geological formations.

A typical seismic survey lasts 2-3 weeks and covers a range of about 300-600 miles. The

intensity of sound waves can reach up to 250 decibels (dB) near the source and can be as high

as 117 dB over 20 miles away. The sound intensity produced by a jackhammer which can

damage human ears in as little as 15 seconds is around 120 dB.

Unlike terrestrial animals, marine mammals rely on sound instead of sight as their primary

sense. Dolphins, whales and seals rely on their sense of hearing to locate prey, avoid

predators, choose migration routes and communicate across long distances. The noise from

seismic surveys can affect the ability of these animals to detect natural underwater sounds,

thereby disrupting these critical activities.



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Numerous scientific studies have echoed what Eskimo subsistence hunters have known for

years: that whales avoid expansive areas where seismic surveys are being

conducted. Appendix 1

1.4.2 Contaminated Drilling Discharges

Offshore oil and gas operations produce a number of waste streams that can contaminate

and alter living seafloor communities. These include produced water, ballast water, deck

drainage, drilling muds, drill cuttings, produced sand, cement residue, blow-out preventer

fluid, sanitary and domestic wastes, gas and oil processing wastes, and slop oil.

Of these, drilling muds, cuttings, and produced water pose the greatest threat to aquatic

environments. Given the technical challenge of dealing with these wastes, offshore

operations generally directly discharge them into the ocean or transport them to shore for

treatment and disposal.

Discharges can physically and ecologically alter the seafloor and associated benthic

(bottom) communities by changing the type of sediments found near platform and well

discharge sites. This change is typically from rocky or higher relief substrate to soft-

bottom sand. Plumes of cuttings can smother fish/crab eggs and larvae in the water

column and sedentary invertebrates on the seafloor such as clams and scallops.

The toxic components of produced water and drilling muds and cuttings can include

heavy metals (mercury, cadmium, zinc, chromium, copper, and others) biocides,

corrosion inhibitors, petroleum residues, and even radioactive material. Scientific

knowledge on the subtle, yet potentially dramatic effects of chronic discharges of drilling

muds and cuttings is limited. However, studies in the Gulf of Mexico have shown that

drilling discharges have caused widespread, long-term, sublethal effects on planktonic

organisms which are key food sources for salmon, other types of fish, whales and seals.

Over the life of a given gas or oil production well, chronic low-levels of contamination

from discharges can accumulate in bottom sediments and cause community-level changes

by which pollution-tolerate organisms are enhanced and pollution-sensitive ones

decline. Pollutants can affect fish populations by impairing reproduction, development

and growth, and by altering behavior which has consequences for individual survival and

recruitment. Appendix 2



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1.4.3 Oil Spills

Federal studies suggest offshore oil and gas production in the North Aleutian Basin

Planning Area (Bristol Bay and southeastern Bering Sea) would result in one or more

major oil spills of more than 1,000 barrels and a number of smaller spills. Surface

currents in the region could push spilled oil up onto the coast of the Alaska Peninsula and

towards the headwaters of Bristol Bay. Oil spill trajectories indicate that oil could

contaminate the mouths of rivers and tributaries where salmon spawn and where

commercial and subsistence salmon fisheries occur.

The spill record for Outer Continental Shelf (OCS) pipelines is significant and is not

improving, raising serious concerns about Bristol Bay OCS development. Recovery of

spilled oil in Bristol Bay is unfeasible as clean-up technology is inadequate in rough sea

conditions, ice, and strong tides and currents.

Shell Corporation public meetings in Anchorage and the Bristol Bay region have shown

industry interest moving closer to the sensitive coastline of the Alaska Peninsula,

increasing the likelihood of an oil spill reaching the coastal bays, lagoons, and sea grass

beds used as nursery grounds for fish and crabs, and as habitat for seabirds and

waterfowl.

1.4.4 Impacts from Oil and Gas Infrastructure

Offshore oil and gas development by its very nature leaves a sizable footprint beneath the

sea and on land. The necessary infrastructure for transporting oil and gas from the ocean

and preparing it to be shipped to markets, would pose serious risks to vital fish, marine

mammal and seabird habitat in the Bristol Bay region. It would also interfere

with subsistence harvesting areas and commercial fishing grounds.

A network of facilities, support bases, and oil and gas transportation infrastructure would

impact hundreds of miles of habitat from the seafloor and water column in the Bering Sea

to coastal areas along the north and south side of the Alaska Peninsula. Shell Oil and

MMS have provided a geographically specific vision for development in Bristol Bay that

calls for subsea pipelines to run through Nelson Lagoon and Herendeen Bay, directly

adjacent to the Port Moller State Critical Habitat area. Onshore pipelines would run

across the Alaska Peninsula National Wildlife Refuge, and terminate at a Liquefied

Natural Gas (LNG) plant and terminal that would be located in the southern (Gulf of

Alaska) side of the peninsula near Pavlof Bay.



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Construction and the presence of pipelines and facilities would lead to the loss of habitat

for marine, coastal and terrestrial species. Degradation of habitat can also occur from

construction noise, heavy equipment, erosion, increased sedimentation and dredging of

seafloor habitat.

1.4.5 Money and Political Influence

An oft dismissed risk is the increased level of influence the oil companies would gain in

the local governments. While there is nothing inherently evil about oil companies, any

time large companies and corporations become entwined in local politics, they spend

inordinately large amounts of money into advertising in order to protect their interests.

This level of influence could potentially have negative effects on the policies of a

shoreline community.

1.4.6 Ecological Impact

A major concern about offshore drilling is its effect on the environment. Since the

majority of rigs are located close to shore, oil spills and seepage can affect coastal

ecosystems. In 1969 over 3 million gallons of oil spilled from a rig off the California

coast near Santa Barbara, which washed up as sludge along 35 miles of shoreline.

Improvements in drilling technology and government regulations have greatly reduced

the number and size of oil spills since then, but they still occur. Spills can also happen

when transporting the oil from the rigs to nearby petroleum plants on the mainland via

shipping and pipelines connected to offshore facilities.

1.4.7 Effect on Tourism

The Gulf of Mexico contains thousands of drilling facilities off the coasts of Alabama,

Mississippi, Louisiana and Texas. The waters—and sight lines for beachcombers—off of

Florida's Gulf Coast are not as cluttered by offshore drilling rigs. Coastal tourism plays an

important part in the economy of all these states. According to Dr. Stephen P. Leatherman

[Ph.D., Environmental Sciences, University of Virginia], aka "Dr. Beach," the beaches of

Texas have suffered due to the amount of offshore drilling in the western Gulf, resulting

in dirtier shorelines.

After a 1979 spill from a rig off the coast of northern Mexico, tourism on Texas beaches

hundreds of miles away fell by as much as 60 percent when oil in the form of tiny tar

balls began washing ashore. Dr. Leatherman, a professor at Florida International

University, believes Florida tourism would be at risk from any new offshore drilling.

"This could lower the value of our beaches...there's a lot more involved than just drilling a

well," he has said. "It's just not good for beaches."



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1.4.8 Risk to Workers

Oil drilling is dangerous enough work on land; at sea the risk to workers is compounded

by the hazards of an ocean environment. An oil rig is like a mini, contained city. Since

petroleum is flammable, the threat of fire is constant. In 1988 167 people perished in an

explosion on the Piper Alpha rig in the North Sea after a gas leak. Capsizing is also a

concern. In 1980 the Alexander Kielland oil platform toppled in high winds, drowning 23

workers. Due to accidents such as these, increased safety precautions and standards have

been enacted, but working on an oil platform remains a risky occupation.



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Chapter 2

Off-Shore Drilling

2.0 Where Did Offshore Drilling Originate?

Offshore drilling began in California, in the Santa Barbara Channel, on a wharf built by a businessman named H. L. Williams. Since that time, offshore drilling has spread into every ocean basin.

2.1 Time Frame

The first "offshore" oil wells appeared in Summerland, CA, in 1887, on wharves built out into Santa Barbara Channel. In 1947, Kerr-McGee Corporation installed the first well beyond the sight of land.

2.2 Function

By 1880, gas was becoming a popular means of illuminating homes and businesses. Heavy industries, like the railroads, depended on oil for lubrication. The first offshore wells in Summerland were built to exploit the natural gas and crude oil resources of the region; when those nearest the ocean performed better than those farther inshore, the rush to the oceanfront--and the ocean--began.

2.3 Size

The first well at Summerland was built on a wharf that extended 300 feet seaward of the beach. As the "Summerland Field" developed, wharves extended progressively farther into the Pacific, with the longest jutting about 1,200 feet from shore.

2.4 Significance

Summerland showed what was possible. In 1926, an wood-framed offshore exploratory well was drilled 1-1/2 miles offshore of Calcasieu Pass, Louisiana by Superior Oil.

2.5 Irony

In 1969, a Union Oil offshore platform six miles off Summerland, CA, had a problem. The Santa Barbara Oil Spill resulted in the creation of the National Environmental Policy Act, the Environmental Protection Agency and Federal regulation of the offshore oil industry.



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2.6 Off shore Drilling Ban History

Since the late 1960s, the United States has debated the pros and cons of offshore oil drilling. Because of a number of legislative actions throughout history, the federal government has rights to control the actions of companies in most maritime waters. Following a series of accidents that resulted in oil spills, a nearly full ban on offshore drilling was put into place at different times by both Congress and the president. However, confrontation continued for years because of the actions of the island nation of Cuba and the rising prices of oil to Americans, culminating in a number of political actions during the early 21st century.

2.6.1 Legal Aspects

According to the United States Constitution, the federal government has power over the navigable waters surrounding the nation. This has been upheld both legislatively and judiciously on several occasions. In 1953, the Submerged Lands Act and Continental Shelf Lands Act both reiterated Commerce Clause that gave the power to the federal government. This was followed by a Supreme Court decision of 1960, which established ownership of the bordering waters out to 3.5 miles as belonging to the states, with the federal government controlling the rest. The exceptions are Texas and Florida with 10.5 miles. These laws have given the federal government authority to control oil drilling facilities operating outside these states.

2.6.2 Early Events

The backlash against offshore oil drilling was heavily sparked by a major oil spill from a Unocal platform off the coast of Santa Barbara, Calif., in 1969. While the initial oil leak was contained, a backlash from the public prompted the state to remove the company's state charter. This was followed in 1981 with a congressional ban on drilling on the outer-continental shelf. The situation grew worse due to a oil spill from the Exxon Valdez tanker in Prince William Sound, Alaska, in 1989. This spill dumped 10.8 million gallons of oil into the ocean, the largest environmental disaster caused by humans in history. The public attention of the event and subsequent backlash from environmentalists pointing out the dangers of offshore drilling prompted President George H.W. Bush to sign a moratorium on the activity in 1990.

2.6.3 Significance

Since the beginning of the offshore drilling ban, a debate has existed within the political framework of the United States. Opponents of the offshore ban believe that opening up oil wells in the oceans off the coast of the country would help drive down fuel prices for consumers as well as make America safe against economic threats from oil-trading countries.



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However, according to the U.S. Department of Energy, the five-year time frame between leasing the areas for oil drills and the actual production time would mean little impact on fuel prices. Between 2012 and 2030, oil production would increase 1.6 percent.

2.6.4 Considerations

One challenge made by proponents of offshore drilling is the fact that the country of Cuba, located within U.S. federal waters, started drilling off of its own coast. In addition, according to Time magazine, the country is prepared to begin drilling between Florida and Cuba. This deal was further announced on Oct. 31, 2008, by a joint conference between Brazil and Cuba in a deal with the Petrobras oil company to supply foreign sources with the oil.



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Chapter 3

Types of Offshore Drilling

3.0 Introduction

Offshore drilling is a process used to explore or collect natural resources, such as crude oil or natural gas. Offshore drilling is an extremely expensive process, even more so than land-based drilling operations. The expense stems from the technological challenges of drilling beneath the water, supporting the operation far from land and weather hazards. There is also the potential human cost, as drilling is inherently dangerous work.

3.1 Site Selection

Before a drilling rig is ever put into place, the site or sites for drilling must be chosen. One of the commonly used methods is gathering seismic data. Essentially, controlled seismic waves are emitted into the Earth's crust (layers of rock under the surface). Different materials will reflect the seismic waves differently and create a picture of what is beneath. Seismologists can interpret this information to make informed guesses about where oil or natural gas pockets might be found.

3.2 Drilling Rigs

Once the site has been selected, a rig is required for test well drilling. Movable rigs are normally used for this purpose. Jack-up rigs that have legs that extend to the ocean floor and a raised platform are used in shallow waters. Semi-submersible rigs are the most common type of rig, and are held in place by a combination of anchors and a lower hull filled with water. A less common type of rig used for test drilling is a drill ship. Drill ships carry drilling equipment and an oil derrick. They are used in very deep water.

3.3 Test Wells

The test well is the real turning point in the process. These are drilled to determine if there is oil or natural gas at the site and whether it is enough to warrant further drilling. To allow the rig on the surface to complete the drilling, a drilling template must be affixed to the ocean floor and connected to rig above. The template guides the actual drilling and assures the drilling position is accurate.

3.4 Drilling Platforms

Assuming a test well provides good return on oil or natural gas, a drilling or production platforms is constructed to replace the movable rig. These are larger facilities than movable rigs and put into place for the life of the well or until the equipment is unusable.



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Dependent on the depth and size of the well, six types of platforms that can be used: fixed platforms, compliant towers, sea star platforms, floating production systems, subsea systems and spar platforms.

3.5 Controversy

Offshore drilling is not a universally accepted practice. The offshore debate in the United States reached a crisis point in late 2008 and early 2009 as the Republicans and Democrats debated the financial and environmental aspects of offshore drilling along the Outer Continental Shelf. The offshore drilling was not commenced but the debate is likely to continue.

3.6 How Offshore Oil Drilling Works

3.6.1 Rigs

Although offshore rigs look similar to those used for onshore drilling, the sea floor can be thousands of feet below the surface. As a result, a platform often has to be erected. Rigs consist of several integral parts, including a power system with engines and generators; a mechanical system with a hoisting system; rotating equipment, which includes a swivel, drill string, turntable, kelly and drill bit; casing that protects the drill hole; a multifaceted circulation system that pulls mud through the hole; a support structure that holds the drill; and high-pressure valves that control the flow of gas or oil to the surface.

3.6.2 Set Up

An oil crew begins by setting up the rig. After drilling to a predetermined depth above the area where oil is suspected to be, the drill bit, color and pipe are placed in the hole. Next, the kelly and turntable are attached, and drilling begins. During drilling, mud---along with cut rock---begins to circulate through the pipe and out the bit. As the hole deepens, the drill pipe usually must get longer; consequently, joints are added. When the desired depth is reached, the drill pipe, collar and bit are removed. A casing is run into the hole to prevent collapse. After the casing pipe has been inserted, cement is poured down the casing pipe into the hole with a bottom and top plug, cement slurry and drill mud, the latter of which makes the slurry fill the area between the hole and casing.

3.6.3 Testing

Once the predetermined drilling depth has been reached, the crew performs tests to confirm the presence of oil. Electrical and gas sensors are lowered into the hole to measure the rock. Drill-stem testing is used to check pressure to determine if the crew has reached reservoir rock. Then, samples of rock are taken. A perforating gun is lowered into the well to put holes in the casing. A small pipe (called tubing) is inserted into the hole, and a packer---used to seal the outer tubing---is inserted inside of the pipe. Finally, a device called a Christmas tree, which helps control the flow of oil, is placed at the top of



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the tubing. In the case of limestone, acid is used to dissolve channels leading to the well. If sandstone is present, a fluid with proppants is pumped into the hole to open oil flow.

3.6.4 Extracting

Once oil starts to flow, the rig is removed, and a pump is put on the head of the well. A pump system---consisting of an electric motor and gearbox, suctions oil up through the well. If need be, another hole can be drilled into the reservoir to inject steam, which thins oil and improves its flow.

3.7 Offshore Drilling Rig Types

There are several types of oil rigs. Each is designed to perform under specific conditions, from shallow water to great depths and areas where the weather is severe or unpredictable. While some oil rigs are built on location over oil deposits, most are constructed or refitted from older ships to create mobile rigs, which can then be towed or propelled into place.

3.7.1 Submersible Oil Rigs

In shallow water, where the depth is 80 feet or less, a submersible rig may be used. Submersible rigs are towed to the drilling location and then submerged until they come to rest upon the ocean floor. Some submersible rigs use anchors to secure their place, but many simply stay in place under their own weight.

3.7.2 Drillships

A drillship is a self-propelled oil rig, which may be built new or retrofitted from an older ship. Older drill ships use conventional anchors to stay in place. More modern drill ships use a computer-controlled system of thrusters to maintain their position over a drilling target. Drillships with computer-controlled positioning are capable of drilling in very deep waters, in which other types of rigs can not operate.

3.7.3 Semi-Submersible Oil Rigs

Semi-submersible rigs may be self-propelled or towed, depending on their design. Ballast is used to submerge the rig once it is in position and it is kept in place either by dynamic computer positioning or by conventional anchors. Semi-submersible rigs are designed for harsh weather conditions, which they endure in part due to their sturdy construction and in part via their sheltered position beneath the ocean's surface.

3.7.4 Jack-Up Oil Rigs

Jack-up rigs rest on legs that are jacked down from the surface once they are in position over the drilling target. Jack-up rigs operate at depths of up to 600 feet, and are towed to position prior to deploying their legs. Once the legs of the rig reach the ocean floor, they



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continue to extend until the body of the rig rests above the water. When the rig rests about fifty feet above the ocean's surface, it is ready to drill.

3.7.5 Production Platforms

Production platforms are permanent structures that are built on-site over deposits of oil or gas. They are commissioned and constructed only after exploratory drilling has lead to the discovery of resources, and cannot be moved once they are in place.

3.8 Offshore Drilling Tools

The tools used in offshore drilling are a combination of state-of-the art computer technology and solid mechanics. The work is dangerous, primarily because of the force of the gas or oil when released from beneath the ocean floor. Offshore drilling is a three-part process that involves many small steps. Tools must be of the highest quality to prevent work-slowing breakdowns and life-threatening conditions.

3.8.1 Drilling Rig Offshore drilling begins with the placement of a drilling rig --- a platform placed in the water. Its purpose is to find the "trap," that is, the place where the oil or gas deposit lies. The engineers use seismic surveys to decide whether or not to drill. They cannot know for certain that the trap will be productive until they conduct exploratory drilling. A drill is sunk to the potential trap with a navigation device affixed to report information back to the rig.

3.8.2 Production Platform

When the trap passes muster, a production platform replaces the drilling rig. Cranes fixed on barges assemble the platform at the location. The depth and area of the trap determine what kind of platform to use. Companies use Jackup rigs, with legs attached to the ocean floor, in shallow water. They use semisubmersible flooring rigs after around 4,000 feet. In the very deepest waters, down to around 8,000 feet, they use drillships. These are equipped with very precise instruments to guide navigation and operations below.

3.8.3 Drills and Pipe

There is a turntable on the platform floor. A pipe with a drill bit is rotated by this turntable to drill into the ocean floor. Longer lengths of pipe are subsequently added to reach deeper in to the earth. The drill bits come in various diameters of up to around 36 inches. Pipe may reach as long as 30 feet. It can take weeks for the drill to hit oil. The two types of drill bits used are rock bits and diamond bits.



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3.8.4 Drilling Fluid

Drilling fluid is made with a combination of water, clay, barite and a variety of chemicals. Its purpose is to cool and lubricate the drill bit as it bores into the ocean floor. It also provides the pressure to keep the oil from bursting upward. The fluid is pumped through holes in the drill bit at a high speed to produce the pressure needed.

3.8.5 Water Separators

When the oil is pulled up from the trap through the pipes it must be separated from the water. The water that has mixed with oil is called produced formation water (PFW). It must be cleaned before it can be returned to the ocean. Mechanical separation devices make it possible to do this.

3.9 Offshore Drilling Techniques

Take away the trappings and specialized rigs and platforms that are inherent to offshore drilling, and the actual drilling process is not that different from onshore drilling. Both types of drilling make good use of rotary, directional and horizontal drilling techniques to extract hydrocarbons, despite the fact that offshore drilling also comes with an entourage of subsea drilling templates, movable and permanent offshore rigs, barges and drillships, as well as a host of offshore platforms to keep the equipment operating intact underwater.

3.9.1 Straight Hole Drilling Just as it sounds, straight hole, or straight line, drilling uses a drill to go straight down into the earth to extract natural gas and oil. While less complicated than other methods, it can also be inefficient. Not all reservoirs can be tapped into vertically, and several vertical drillings may be necessary, which generate additional waste.

3.9.2 Directional and Horizontal Drilling

Directional drilling is an exciting extraction technique in onshore and offshore drilling in that previously inaccessible reservoirs, long and thin reservoirs and reservoirs under shallow lakes can be reached after drilling at least 2,000 feet into the ground. With just one rig, 20 or more wells can be drilled, making it an economically productive technique.

Horizontal drilling, unlike directional drilling, can make a 90-degree turn after drilling only a few feet into the ground. Among the three main types of horizontal wells (short, medium and long radius), long radius is a good choice for offshore drilling, as these wells can have curvature radii of 1,000 to 4,500 feet with horizontal extension capability of 15,000 feet. A single drilling in the middle of a remote expanse of water can therefore be quite effective and practicable.



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3.9.3 Rotary Drilling

Another dual-purpose, onshore and offshore drilling method is rotary drilling, or use of a rotating drill bit to dig into the earth. Rotary drilling consists of four key types of equipment: prime movers, hoisting equipment, rotating equipment and circulating equipment.

Prime movers give power to all the other pieces of equipment, whether through diesel or natural gas engines or turbines. Hoisting equipment helps lift and lower the rotating equipment in the event those parts need to be replaced. The rotating equipment, consisting of a drill-pipe, the drill bit and drill collars, does the actual drilling. Circulating equipment is needed to cool down and lubricate the drill bit, remove debris, control pressure and slather the machinery with "mud," or drilling fluid. A blowout preventer located underneath the rig also helps seal the well in the event that the drilling fluid is unable to control any surges of upward pressure emanating from the oil and gas below.

3.10 Offshore Drilling Dangers

Offshore drilling is done by rigs designed to remain steady in gulf and ocean waters. These specialized rigs drill wells and insert piping in water depths of 200 to 400 feet to bring oil and natural gas up to the surface, where it is then transported to the shore. Offshore drilling can be be dangerous because of the sensitive marine environment in which it occurs. Personnel mistakes, equipment failure, operational malfunctions or natural phenomenon like tropical storms or hurricanes can all have dangerous impacts. Oil and hazardous waste releases can also impair marine life and habitats. However, there are standardized safety precautions for offshore drilling to prevent dangerous activities and impacts from occurring.

3.10.1 Personnel Mistakes and Equipment Failure

There are many opportunities for personnel mistakes during offshore drilling activities, including rotary drilling, well servicing and use of oil field explosives--as well as during equipment repair, maintenance and construction. Personnel mistakes result in injuries to personnel and oil releases to the marine environment.

Offshore drilling rigs and wells operated on platforms in the ocean involve many equipment components that require regular inspections and maintenance. Specific safety equipment features that need proper maintenance include blowout preventors (BOPs), drill fluid conditioning and cleaning systems, and casing and tubing operations

3.10.2 Operational Malfunctions

Spills and releases can occur in any step along the way of the drilling and piping process if proper procedures are not followed. And even with proper operational procedures,



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every well drilled produces large quantities of mud contaminated with mercury and lead, which is disposed of in the ocean.

Once specific operational malfunction is when high-pressure testing operations fail, resulting in a blowout. The natural pressure forces oil, gas and other wellbore fluids uncontrollably into the marine environment.

3.10.3 Natural Phenomenon

A tropical storm or hurricane can damage rigs (especially those constructed prior to the 1990s when safer construction practices were instituted) and move platforms great distances, releasing greater quantities of oil and dispersing oil over wider geographic areas. Storm events are high-risk, low-probability events but do create dangerous scenarios because safety precautions are hindered during the event.

3.10.4 Safety

Personnel safety for offshore drilling endeavors includes proper training in compliance with OSHA and American Petroleum Institute standards. Standards are provided specifically for operations on ocean platforms and for personnel, who generally work and live on the platform for two weeks and then must be transported back to shore. Standard operating procedures for offshore drilling also compensate for the marine environment and seafaring qualities of equipment and processes.

Continual and consistent review of personnel safety procedures and proper operation and maintenance of equipment can decrease oil spills and improve productivity.

3.10.5 Offshore Drilling Dangers

Offshore drilling provides 24 percent of U.S. oil and 25 percent of U.S. gas supply, buffering national security by decreasing imports, but not without risks. Offshore drilling can produce anoxic conditions through the release of oil and hazardous materials, killing marine life and damaging habitats. Long-term cumulative impacts of offshore drilling on marine environments indicate species declines and habitat destruction. It is theorized, however, that once offshore drilling and associated oil spills cease in a location, natural recovery will take place.



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Chapter 4

Pros & Cons of Offshore Oil Drilling

Pro: More Domestic Production

More offshore drilling will lead to greater domestic oil production and less reliance on

imported oil, much of which comes from politically unstable regions, such as the Middle

East.

Pro: Lower Pump Prices

Offshore drilling will increase the supply of oil, resulting in lower gasoline prices,

according to supporters.

Pro: Increased Government Revenues

Supporters of offshore drilling say that opening restricted areas to offshore oil production

will generate billions in state and federal revenues through royalties.

Con: Minimal Price Impact

Opponents say the additional oil generated through expanded offshore drilling will not be

enough to greatly affect world oil prices.

Con: Carbon Emissions

Expanded offshore drilling will not reduce emissions of carbon dioxide, which

contributes to warmer global temperatures.

Con: Environmental Hazards

A 1969 accident that spilled millions of gallons of oil off the California coast led to

restrictions on offshore drilling. Increased drilling makes such accidents more likely to

occur



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4.1 Benefits of Offshore Drilling

Offshore drilling often receives a bad reputation for causing environment problems, however there are benefits to offshore drilling. Offshore rigs help the local economy, create jobs, reduce dependency on foreign fuels and surprisingly also create homes for marine life. In addition, the majority of oil spills occur during the transportation of oil not during the drilling, although there are obvious exceptions. According to Humberto Fontova, the "Outer Continental Shelf, holds an estimated 115 billion barrels of oil and 633 trillion cubic feet of natural gas."

4.1.1 Jobs

Offshore oil rigs provide many primary, secondary and tertiary jobs. Primary workers are those who work on the rig itself and include specialized technicians, labourers, cooks, doctors, scientists and a number of other specialized workers. Secondary jobs are those that support the rig: food distributors who bring in supplies and parts manufacturers who help set up the rig itself. Tertiary jobs are found among those who transport the oil to refining stations and work onshore in labs and refining stations. Offshore oil rigs keep many people working and help support local economies.

4.1.2 Domestic Fuel

Offshore drilling helps the United States harvest rich deposits of oil that are located on domestic soil. This reduces dependency on foreign oil and brings the cost of oil down for the average American. Expensive transportation fees are avoided as oil harvested and refined domestically costs much less to transport.

4.1.3 Environment

Surprisingly the environment can benefit from offshore drilling, if there are no accidents. Offshore rigs are massive structures in the ocean that attract a wide variety of marine life. Fish, birds and other sea creatures come to the rig and make it their home. The rig acts as an artificial reef that helps life flourish as many animals use it for breeding.

4.2 Bad Effects of Offshore Drilling

Offshore drilling obtains oil and gas from beneath the ocean floor. The drills attach to a platform on the surface of the water and extend as deep as necessary. Offshore drilling is



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a controversial source of resources because of the difficulties involved and potential environmental damage.

4.2.1 Environmental Disadvantages Given the chance of oil spills, offshore drilling poses a serious threat to marine ecosystems. In a spill, the toxicity of the oil harms marine animals and their habitat. The threat of oil spills comes from drilling platforms and moving oil tankers. Any location in the path of a tanker faces potential risk. Furthermore, the movement of ocean currents can amplify the scope of such a disaster. Oil has a particularly damaging effect on coastal life as it moves with the tide. In 1989, for example, the Exxon Valdez oil spill in Prince William Sound damaged more than 1,000 miles of Alaskan coastline. The damage to marine wildlife populations was vast.

4.2.2 Environmental Effects of Platforms

Drilling platforms pose a potential risk to the ocean environment. The platforms can have drastic and adverse effects on marine life below. Platform construction displaces creatures on the ocean floor, and the apparatus itself creates a strange new obstacle in the otherwise natural marine world. Platforms generally create an abnormal fixture in the world of marine creatures, disrupting the ecosystem and potentially attracting non-native species.

4.2.3 Practical Difficulties and Risks

Offshore drilling has potential negative effects on human populations. Many risks complicate the logistics and maintenance required to operate a drilling platform. Accidents such as explosions and mechanical failure occasionally occur. In 1980, a drilling platform called the Alexander Kielland collapsed, killing 123 people. Many explosions have also occurred, such as the 2001 explosion of the Petrobas 36 Oil Platform. In an oil spill, the lengthy recovery process is an economic burden. The spills themselves wreak havoc on local and global fishing economies.

4.3 Weighing the Benefits & Costs of Offshore Drilling

Two years ago BP’s Deepwater Horizon oil drilling rig in the Gulf of Mexico exploded, killing 11 workers. The exploratory well began gushing oil at an estimated rate of 5,000 barrels per day when the blowout prevention system failed. The growing oil slick menaces the marshes and beaches of Louisiana, Mississippi, Alabama, and Florida. Should the slick come ashore, previous research suggests the deleterious effects on fisheries and wildlife would be substantial and long-lasting.



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As someone who has enjoyed the sugar white sands of Alabama’s beaches, it is a terrible shame that they are at risk of being despoiled by oily muck. But as someone who also enjoys the conveniences of modern civilization including the on-demand mobility offered by airplanes and automobiles that enable me to visit those beaches, I understand trade-offs.

Opponents of offshore drilling have jumped on the spill as evidence that offshore drilling is inherently dangerous, and not worth the risk. They see the blowout as evidence that the recently lifted moratorium on offshore drilling in parts of the outer continental shelf should be reinstated. Miyoko Sakashita of the Center for Biological Diversity decried “the absurdity of the claims by the oil industry and politicians beholden to that industry that offshore oil and gas development is safe." As a consequence, the center is urging the Obama administration “to reinstitute a moratorium on new offshore oil leasing, exploration, and development on all our coasts.” The Natural Resources Defense Council is also calling for a “time-out” on any further offshore oil drilling until an independent investigation of the BP spill is completed. On April 30, the Obama administration heeded the call for a time-out and halted plans to expand offshore drilling until an investigation into the causes of the BP blowout are complete.

But in deciding whether or not to continue offshore exploration for oil and gas, a calm quantitative approach makes more sense than a rush to ban drilling after seeing some pictures of oily birds. It would be useful to figure out if the costs, economic and ecological, outweigh the benefits of producing offshore oil and gas. Luckily, a recent study by Georgetown University economist Robert Hahn and Milken Institute economist Peter Passell offers some insight to this question. Published in the December 2009 issue of Energy Economics, their study “The economics of allowing more U.S. oil drilling,” finds that the benefits of producing offshore oil greatly outweigh the costs.

In their analysis, Hahn and Passell look at three types of benefits: producer revenues, lower prices to consumers, and less fluctuation in oil prices. These benefits are considered in a scenario in which oil is priced at $50 per barrel, and in another in which it goes for $100 per barrel. (The current price is around $85 per barrel.) At $50 per barrel they estimate that 10 billion barrels of oil would be recoverable from the off-limits outer continental shelf, and at $100 this rises to 11.5 billion barrels.

On the cost side of the ledger they calculate that it would cost $17 per barrel to produce offshore oil at $50 per barrel and $20 per barrel at $100 per barrel. They incorporate a Minerals Management Service estimate of $700 million as the cost of the environmental damage caused by producing 10 billion barrels of oil offshore. They include an estimate of damage caused by greenhouse gases produced by burning the oil as fuel, and the direct costs of local air pollution, and traffic congestion and accidents. So what did they find?

At $50 per barrel, the benefits of offshore oil production in the formerly off limits areas of the outer continental shelf would garner $492 billion in revenues, $42 billion in lower oil prices, and reduce the cost of oil price disruptions by $42 billion, yielding total



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benefits of $578 billion. The direct drilling costs would come to $166 billion, environmental costs $1 billion, greenhouse gas damages $1 billion, local air pollution $28 billion, traffic congestion $28 billion, and traffic accidents $32 billion, for a total cost amounting to $255 billion. So at $50 per barrel the benefits of producing 10 billion barrels of offshore oil would be $323 billion greater than its costs.

At $100 per barrel, outer continental shelf oil production of 11.5 billion barrels of oil would reap $1.15 trillion in revenues, lower oil prices by $99 billion, and reduce the costs price disruptions by $51 billion, resulting in total benefits of $1.3 trillion. Drilling costs would be $238 billion, environmental costs and greenhouse gas damages would total $2 billion, the costs of local air pollution, traffic congestion, and traffic accidents would be $22 billion, $33 billion, and $38 billion respectively. So the total costs of producing 11.5 billion barrels of offshore oil would be $332 billion. Hahn and Passell calculate that at $100 per barrel, the net benefits of producing offshore oil would come to $967 billion, or a trillion dollars. They note that even if the total costs were doubled in both scenarios, “the qualitative conclusion that resource development passes any plausible benefit–cost test still holds.”

But perhaps the environmental costs used by Hahn and Passell are too low. Could they be wrong about the cost of greenhouse emissions? Hahn and Passell note that even at the highest social cost of carbon at $321 per ton suggested by British economist Nicholas Stern, the total benefits of producing offshore oil are still positive. In that case, the net benefits drop from $325 billion to $120 billion at $50 per barrel, and from $975 billion to $725 billion at $100 per barrel.

As for other environmental impacts, analysts at the Environmental Protection Agency (EPA) have devised a Basic Oil Spill Cost Estimation Model to try to figure out the costs of various types of spills. For example, the EPA model projects that the socioeconomic costs of spills over a million gallons is about $60 per gallon and the environmental costs are $30 per gallon. So if the BP blowout continues as-is for a total of 50 days, it will spew 10 million gallons into the Gulf, resulting in $900 million in costs. Applying the model’s highest socioeconomic sensitivity adjustment factor of 2 raises those costs to $1.2 billion, and applying the EPA formula including the highest vulnerability (wildlife) and habitat sensitivity factor (wetlands) raises those costs to nearly $1 billion, for a total of $2.2 billion.

This figure is basically the same as the total clean up costs of the biggest oil spill in U.S. history: In 1989, the Exxon Valdez oil tanker leaked 250,000 barrels of crude oil (about 10 million gallons) after being run aground on a reef in Alaska’s Prince William Sound. The BP blowout will eclipse the Exxon Valdez spill if it continues flowing for another 33 days. The ultimate clean up costs for the Exxon Valdez accident amounted to about $2.2 billion, with additional legal costs and damage payments of $2.3 billion. Some analysts are estimating that the costs for clean up and payment for economic losses from the BP



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spill might reach as high as $12.5 billion. As it should be, BP’s corporate leadership has declared that the company will be responsible for paying for the costs of the spill.

In his book, Normal Accidents: Living with High Risk Technologies (1984), Yale University sociologist Charles Perrow noted that when a technology fails, it often does so because “the problem is just something that never occurred to the designers.” Assuming no malfeasance, whatever went wrong with the Deepwater Horizon drill rig will likely uncover just such a problem and future designers will fix it. Progress is a trial and error process, and increasing safety results from learning how to make better trade-offs over time between risks. Despite this current disaster, offshore oil drilling remains a risk well worth taking.

4.4 Modelling Oil Spill Response And Damage Costs

The EPA Basic Oil Spill Cost Estimation Model (BOSCEM) was developed to provide the US Environmental Protection Agency (EPA) Oil Program with a methodology for estimating oil spill costs, including response costs and environmental and socioeconomic damages, for actual or hypothetical spills. The model can quantify relative damage and cost for different spill types for regulatory impact evaluation, contingency planning, and assessing the value of spill prevention and reduction measures. EPA BOSCEM incorporates spill-specific factors that influence costs – spill amount; oil type; response methodology and effectiveness; impacted medium; location-specific socioeconomic value, freshwater vulnerability, habitat/wildlife sensitivity; and location type. Including these spill-specific factors to develop cost estimates provides greater accuracy in estimating oil spill costs than universal per-gallon figures used elsewhere. The model’s basic structure allows for specification of response methodologies, including dispersants and in situ burning, which may have future applications in freshwater and inland settings. Response effectiveness can also be specified, allowing for analysis of potential benefits of response improvements.

4.4.1 Introduction

Regulatory analysis, cost-benefit analysis, resource planning, and impact analysis related to oil spills requires putting a value on the damages that oil spill cause. Use of a universal dollar-per gallon (or dollar-per-barrel) cost for oil spill response, socioeconomic and environmental damage has been applied in many cases (e.g., Office of Management and Budget, 2003), but this methodology overlooks the important factors in oil spill cases that can influence costs by orders of magnitude. The costs of a particular oil spill are related to a large number of factors, most notably: spill amount, oil type characteristics, response methodology and effectiveness, impacted medium or substrate type, location-specific socioeconomic and cultural value, location-specific freshwater vulnerability, location-specific habitat and wildlife sensitivity, year of spill (both in terms of inflation adjustments and probable response



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effectiveness for past and future cost projections), and the region or urban area impacted. To provide the EPA Oil Program Center with a simple, but sound methodology to estimate oil spill costs and damages, taking into account spill-specific factors for cost-benefit analyses and resource planning, the EPA Basic Oil Spill Cost Estimation Model (BOSCEM) was developed.

4.4.2 Methodology

EPA BOSCEM was developed as a custom modification to a proprietary cost modeling program, ERC BOSCEM, created by extensive analyses of oil spill response, socioeconomic, and environmental damage cost data from historical oil spill case studies and oil spill trajectory and impact.

In addition, elements of habitat equivalency analysis as applied in Natural Resource Damage Assessment and other environmental damage estimation methods, such as Washington State’s Damage Compensation Schedule and Florida’s Pollutant Discharge Natural Resource Damage Assessment Compensation Schedule (Plante, et al., 1993) were incorporated into the environmental damage estimation portion of ERC BOSCEM. Formulae, criteria, and cost modifier factors for estimating socioeconomic damages, including impacts to local and regional tourism, commercial fishing, lost-use of recreational facilities and parks, marinas, private property, and waterway and port closure, were derived from historical case studies of damage settlements and costs, as well as methods employed in other studies The model requires the specification of oil type and amount and primary response methodology and effectiveness to determine the base costs. Cost modifiers based on location medium type, location-specific relative socioeconomic/cultural value category, location-specific freshwater use, location-specific habitat and wildlife sensitivity category, and year of spill (in the case of future and past cost estimations), are then applied against the base costs. The base costs for response costs, socioeconomic costs, and environmental damages are shown in Tables 1 – 3. The modifier factors are shown in Tables 4 – 8. The basic model diagram for EPA BOSCEM depicting the interrelationships between cost factors is shown in Figure 1.

To apply EPA BOSCEM to estimate costs for a hypothetical spill, the following steps are taken:

Input of spill criteria:

1. Specify amount of oil spilled (in gallons);

2. Specify basic oil type category (as in Tables 1 – 3);

3. Specify primary response methodology and effectiveness (as in Table 1);

4. Specify medium type of spill location (as in Table 4);

5. Specify socioeconomic and cultural value of spill location (as in Table 5);



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6. Specify freshwater vulnerability category of spill location (as in Table 7);

7. Specify habitat and wildlife sensitivity category of spill location (as in Table 8);

Note that if no specification is made for any of the input criteria, or if these factors are not known, the “default value” indicated in each table is used.

Determination of spill costs:

1. To calculate spill response cost, multiply the base per-gallon response cost based on oil type/volume/response method and effectiveness, as determined from Tables 1 or 2, by the medium modifier in Table 4 and by the spill amount: per-gallon response cost X medium modifier X spill amount = total response cost

2. To calculate socioeconomic damages, multiply the base per-gallon socioeconomic cost based on oil type/volume, as determined from Table 3, by the appropriate socioeconomic and cultural damage cost modifier in Table 4 and by the spill amount:

per-gallon socioeconomic cost X socioeconomic cost modifier X spill amount

= total socioeconomic damage cost

3. To calculate the environmental damages, multiply the base per-gallon environmental damage cost based on oil type/volume, as determined from Table 4, by the freshwater vulnerability modifier added to the habitat/wildlife sensitivity modifier and multiplied by 0.5, all multiplied by the spill amount:

per-gallon environmental cost X 0.5(freshwater modifier + wildlife modifier) X

spill amount = total environmental damage cost

Note that in the use of cost modifiers, if there are spill situations in which the spill falls partly into one category and partly into another, estimate the relative proportion of the spill impact (by volume or area covered) in each of the categories and compute the weighted average of the modifiers to determine a combination modifier. For example, if impacted waters have a mixed use of 70% industrial and 30% wildlife use, the freshwater vulnerability would be computed as:

Fresh water vulnerability modifier = 0.7(industrial) + 0.3(wildlife) = 0.7(0.4) + 0.3(1.7) = 0.79.

The costs can be added together for a total spill cost. All of the costs can be adjusted by regional/urban area- and year-specific consumer price index factors to adjust for regional differences in costs and inflationary changes in costs for past spills or future past projections.

4.4.3 Results

EPA BOSCEM was used to estimate the costs of oil spills in navigable inland waterways in the EPA Jurisdiction Oil Spill Database, based on the characteristics of each spill. The data



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set included 42,860 spills of at least 50 gallons that occurred during the years 1980 through 2002.

Each spill was classified by the input criteria of oil type and volume and general location- specific characteristics to determine the appropriate cost modifiers. The response, socioeconomic, environmental, and total costs were also adjusted for regional/urban area consumer price index and annual inflationary differences. All costs were adjusted to 2002 dollars. An assumption of increasing response effectiveness was also incorporated into the calculations. The costs for oil spills in inland navigable waterways for the years 1980 through 2002 are shown in Table 9. Over the 23-year period, estimated total costs for inland navigable waterway oil spills was $63.2 billion, or, on average, $2.7 billion annually. This is nearly the equivalent of an Exxon Valdez-magnitude spill event over the inland waterways each year.

4.4.4 Discussion

Each oil spill is a unique event involving the spillage or discharge of a particular type of oil or combination of oils that may cause damage to the local and/or regional environment, wildlife, habitats, etc., as well as to third parties. No modelling method can ever exactly determine or predict costs of an oil spill. Yet, there are patterns that emerge with respect to damages upon detailed analyses of oil spill case studies. For example, heavier oils are more persistent and present greater challenges – and thus costs – in oil removal operations than lighter oils, such as diesel fuel. Heavier oils, being more visible and persistent, have greater impacts on tourist beaches and private property. At the same time, lighter oils with their greater toxicity and solubility are more likely to cause impacts to groundwater and invertebrate populations. Greater effectiveness in oil removal tends to reduce environmental damages and socioeconomic impacts.

Other factors, such as spill location, can also have significant impacts on spill costs and damages. A diesel fuel spill in an industrial area will likely have less impact and require a less expensive cleanup than one that occurs in or near a sensitive wetland. EPA BOSCEM incorporates these types of factors into a simple methodology for estimating the costs of “types of spills” that may be analyzed in a cost benefit analysis or for assessing which types of spills (oil type, location, etc.) that are causing the greatest impacts. It is important to note that with respect to “environmental damage” cost estimations, EPA BOSCEM is not a substitute for a federal- or state-level NRDA process. But, the model can provide a method for estimating relative differences in natural resource damage impacts from different types of spills.

The model allows for cost and damage estimation of different oil spill response methodologies, including different degrees of mechanical containment and recovery, as well as alternative response tools of dispersants and in situ burning that may have greater future applications in freshwater and inland settings. Response effectiveness can also be specified allowing for analysis of potential benefits of research and development into response



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improvements. Additionally, EPA BOSCEM is adaptable to future updates as research and development efforts on oil spill cost modelling provide even more reliable spill base costs and spill factor modifiers.



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Chapter 5

Technical Risks

5.0 Risks of Offshore Oil Drilling: Causes and Consequences of British Petroleum

Oil Rig Explosion

The British Petroleum oil rig explosion in the Gulf of Mexico has left a legacy of

environmental pollution, loss of businesses and health effects. The various stakeholders;

British Petroleum, Harliburton, government regulators and Transocean Management Ltd

are partly responsible for the safety of Macondo oil rig and they are accountable for

negligence, oversight, cost-cutting and shoddy technical fixes which eventually resulted

in the explosion. Several species of wildlife and ecosystems were threatened. Efforts were

made to cap the well, clean the oil, and rehabilitate affected animals. In spite of the

ongoing restoration efforts, there is still uncertainty regarding long-term viability of

restored ecosystems.

5.0.1. Introduction

The drilling, extraction, refinery, transportation, storage and consumption of oil and gas are inherently risky ventures. Accidental oil spills are inevitable due to technical, logistical, human, policy, market, financial, political, geologic and environmental factors that influence or compromise the safety of oil rig operations. Management of oil wells and drilling operations turn to be complex due to a number of multi-national companies involved. Ownership, mergers, strategic agreements, contracts, and resulting roles and responsibilities of actors leave much to be desired. The Deepwater Horizon in the Gulf of Mexico was built by Hyundai. The rig was contracted out to British Petroleum (BP) to operate the Macondo oil well. BP was the operator and principal developer of the Macondo Prospect. BP purchased the drilling rights from the US Minerals Management Service (MME) in March 2008.

However, the unit was operated by Transocean Management Ltd under contract for BP. Transocean is the world’s largest offshore drilling contractor, with a current fleet of some 139 mobile offshore units. Sub-contractors, such as Halliburton Energy Services is the provider of the engineering services, materials, testing, mixing, and pumping for cementing operations. Weatherford has been involved in casting components including the float collar, shoe and centralisers, Dril-Quip, a provider of wellhead equipment, including casting hangers, seal assembly, and lockdown sleeve used on the well and



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Oceaneering is responsible for remote-operated vehicle (ROV) equipment and personnel (Lee & Garza-Gomez, 2012).

On April 20, 2010, Deepwater Horizon, a drilling rig owned by Transocean and leased by BP to explore the Macondo oil field, exploded, caught fire, and sank resulting in the death of 11 rig workers and several people sustained varying degrees of physical and psychological injuries (National Commission, 2011). Investigations into the accident revealed that there was recurring theme of missed warning signals, failure to share information, oversight, and a general lack of appreciation of the risks. Ironically, stakeholders involved in the oil drilling blamed and counter-blamed each other for the disaster. Attempts made by reporters to uncover the cause of the rig explosion was met by refusal of company officials to speak with reporters, intimidation of workers who divulge information, suspicion of foul play by sub-contractors and stonewalling of government officials during congressional hearings.

5.0.2 Evolution of Oil Drilling in the US

Beginning in the 1890s, oil companies had drilled wells in the ocean, but from wooden piers connected to the shore. In the 1930s, Texaco and Shell Oil deployed moveable barges to drill in the south Louisiana marshes, protected from extreme conditions in the ocean. In 1937, two independent firms, Pure Oil and Superior Oil, finally plunged away from the shoreline, hiring Texas construction company Brown & Root to build the first freestanding structure in the ocean. It was located in the Gulf of Mexico State Lease No. 1, in 4.27 meter of water, a 2.41 kilometers offshore and 20.92 kilometers from Cameron, Louisiana. In March 1938, this structure brought in the first well from what was named the Creole Field (National Commission, 2011). The Creole platform severed oil extraction from land—and did so profitably, setting in motion the march of innovation into ever-deeper waters and new geological environments offshore. The Gulf of Mexico, where offshore drilling began, remained a vital source of oil and gas for the United States.

On January 28, 1969, a blowout on Union Oil Company Platform A-21 in the Santa Barbara Channel released about 2 071.99 square kilometers slick of oil that blackened an estimated 30 miles of California beaches and lethally soaked sea birds in the gooey mess. Although the well’s blowout preventer worked, an inadequate well design allowed the hydrocarbons to escape through near-surface ruptures beneath the seafloor. It drew a $31.5 million suit against the company by Louisiana oyster fishermen and a $70 million suit from shrimp fishermen (National Commission, 2011). During the 1970s and 1980s, the frequency of blowouts did not decline significantly, but there was a sharp drop in the number of catastrophic blowouts, and fewer casualties and fatalities were associated with them (Danenberger, 1993). U.S. oil production peaked in 1970. Along with the OPEC oil embargo of 1973 and consequent skyrocketing price of oil products, this event spurred the quest to develop new offshore reserves.

A major oil disaster occurred on March 1989, the supertanker, Exxon Valdez ran aground on Bligh Reef in Prince William Sound, Alaska (Table 1). The tanker was loaded with



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about 1.2 million barrels of oil. Close to 250 000 barrels was spilled into what is considered to be one of the most pristine and ecologically rich marine environments of the world (Botkin et al., 2006). It caused the death of estimated 13% of harbour seals, 28% of sea otters and 100 000 - 645 000 seabirds (Botkin et al., 2006). It resulted in the passage of the U.S. Oil Pollution Act of 1990. It cost more than U.S. $3 billion to clean up but the use of high-pressure hot water and the spraying of rocks also caused further death to organisms found along the shoreline.

Another accident happened in the Galapagos Island in January 2001 when small oil tanker (Jessica) carrying light diesel oil made a navigational error along the coast of Ecuador and spilled diesel into the ocean (Table 1). The United States government responded quickly with Coast Guard ship which pumped oil from the damaged tanker. Some of the oil was washed ashore onto a small island, injuring birds, seals, and other marine life. Many experts and analysts believe that the more recent episode in the Gulf of Mexico in April 2010 is the largest accidental marine oil spill in the history of the petroleum industry.

5.0.3 Basic Knowledge of Deep Water Oil and Gas Prospection and

Drilling Techniques

The deepwater environment is cold, dark, distant and under high pressures and the oil and gas reservoirs, when found deep in the Earth, exist at even higher pressures (thousands of



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pounds per square inch). Superior techniques now allow scientists to virtually see the interior of the oil and gas field or sea-bed formation. Then, super computers process the data to create fully visualized multi-dimensional representations of the sub-surface. Recently, magnetic and seismic surveying are employed. A compressed air gun is used to create shock waves that travel under the surface of the Earth. These reflections are known to travel at varying speeds depending on the rock layers density through which they pass. Sensitive vibration detectors are then used to detect these reflections of the sent shock waves.

Upon completion of surveying, they identify the best location to drill an exploratory well; the area is marked using marker buoys. Exploratory drills are brought forward and if government permission is granted, the drilling process then takes place to determine where hydrocarbons are present, accumulated and to measure the area and thickness of the oil-bearing reservoir (U.S. Department of Energy, 2006). The technology used for the Gulf of Mexico is made up of two parts. First, the oil crew drill several holes which allow the rig to pass through. A rectangular pit is dug around the actual drilling hole to give space for the drilling accessories and the workers. Once the drill reaches the oil deposits, the well needs to be sealed for production and usually a mixture of mud or seawater is used to hold the plug in place until a more permanent cap can be applied.

Deep-sea oil drilling involves drilling into the Earth’s crust at a 90 degree angle, and rocks are fractured by a highly pressurized mixture of water and sand to keep the crack open (Colleran, 2010). The drilling column is also capable of changing pressure inside the drill to form a seal around the well. Each well, indeed, has its own “personality” that requires maintaining an extremely delicate balance between the counteracting pressures of the sub-surface formation and drilling operation. Drilling mud, which is used to lubricate and cool the drill bit, plays a critical role in controlling the hydrocarbon pressure in the well. The weight of the column of mud in a well exerts pressure that counterbalances the pressure in the hydrocarbon formation. However, if the mud weight is too high, it can fracture the surrounding rock, potentially leading to “lost returns”—leakage of the mud into the formation (National Commission, 2011). It is a delicate balance. The drillers must balance the reservoir pressure (pore pressure) pushing hydrocarbons into the well with counter-pressure from inside the wellbore. An uncontrolled discharge of oil and gas in the well is known as a blowout. Under such conditions, methane hydrates or gas locked in ice (“fire ice”) forms at low temperature and high pressure can often be found in sea-floor sediments. Temperature and pressure changes caused by drilling can activate the release of 4.53 cubic metres of gas from 0.028 cubic metres of methane, collapsing surrounding sediments.



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5.0.4 The Macondo Oil Rig Explosion: Course and Causes

BP’s Macando well was located in 1 500 metres of water 75 kilometres southeast of Grand Island, Louisiana (McDonald, 2010). The Macondo oil rig explosion in the Gulf of Mexico on April 20, 2010 appears to have been caused by a bubble of methane gas which escaped from the well, moved up the drill column and ignited. The first explosion occurred at approximately 9:49 p.m. It burst through the floor of the rig and an intense fire engulfed the platform (Tromans, 2010). On the drilling floor, the Macondo disaster claimed the lives of 11 men who worked on the rig, and seriously injured many others. The unit burned for over a day, sank on April 22, and now lies at the bottom of the Gulf of Mexico. The initial oil spill was discovered by BP but it was not reported immediately which suggests an attempt to cover up. The first reports of the oil leak came on April 22, 2010, when a large slick was observed by the US Coast Guard.

The Macondo blowout was the product of several individual missteps and oversights by BP, Halliburton, Transocean and government regulators. The tragic explosion and oil spill revealed a corporate culture at BP that had consistently neglected worker safety and environmental standards by using cost-cutting and poor quality methods (Su et al., 2009). A report released by BP revealed that decisions made by multiple companies and work teams contributed to the accident which arose from a complex and interlinked series of mechanical failures, human judgments, engineering design, operational implementation and team interfaces (BP, 2010a). The National Commission on the BP Deep Horizon oil spill (2011) indicated that BP did not engage in corporate social responsibility (CSR) at the management level and importantly did not act in socially responsible ways. There were several missteps and the Commission (2011) of inquiry into the causes of the accident identified the following problems:

(1) There was no standard procedure for running or interpreting the test in either regulations or written industry protocols.

(2) BP and Transocean had no internal procedures for running or interpreting negative-pressure tests and had not formally trained their personnel to do so.

(3) The BP Macondo team did not provide the well site leaders or rig crew with specific procedures for performing negative-pressure tests at Macondo.

(4) BP did not have in place (or did not enforce) any policy that would have required personnel to call back to shore for a second opinion about confusing data.

(5) Finally, due to poor communication, it does not appear that the men performing and interpreting the test had a full appreciation of the fact that the well lack integrity (National Commission on BP Oil Spill, 2011).

Also, investigations revealed that some of the software did not work as expected because the drill control display screens were shut down on numerous occasions before the



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explosion. A chief engineer of Transocean reported after the accident that the screens froze and locked all the data. This prevented them from reporting the problem properly and promptly. Other software problems include missed and erroneous alarms that caused severe damage to the rig equipment.

After the first explosion, crewmembers on the bridge attempted to engage the rig’s emergency disconnect system (EDS). The EDS should have closed the blind shear ram, severed the drill pipe, sealed the well, and disconnected the rig from the Blowout Preventer but none of that happened. The crew should have diverted the flow overboard when mud started spewing from the rig floor. When BP management realized that the early efforts to stop the flow of oil had failed, a primary option was to drill a relief well to intersect the Macondo well at its source and enable a drilling rig to pump in cement to stop the flow of oil. A device known as a packer is sent down to reinforce the walls, by expanding against the wall to prevent cave-ins and leaks. The most crucial part of the whole system is the blowout preventer. This is a structure with a series of valves used to control the flow of oil from the well, seal off the wellhead and to prevent a “blowout”. A blowout preventer (weighing 204 116.6 kilograms) stops oil from gushing out. Unfortunately, the Macondo blowout occurred because bubble of highly inflammable methane gas escaped up the shaft and ignited, causing the explosion (Figure 1).



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Each of the mistakes made on the rig and onshore by industry and government increased the risk of the well blowout; the cumulative risk that resulted from these decisions and actions was both unreasonably large and avoidable. BP blamed its contractor Transocean for failing to prevent the disaster while Transocean blamed BP for not heeding the safety related warnings Transocean gave. BP in turn blamed Halliburton for poor quality of the cementing, which allowed hydrocarbon to get into the well. Halliburton was criticized for failing to highlight the problems of the cement testing by burying the report which had revealed that the cementing process did not meet industry standards. The Congressional investigation revealed that BP officials and Chief Executive, Tony Hayward had chosen the riskier type of well casing in order to reduce costs and save time, only days before the blowout. Other problems include repeated losses of power and the malfunctioning of a key computer system used to monitor drilling operations. All of the problems had a common link in that they involved bad decisions, missed warnings and worker disagreements.

Government also failed to provide the oversight necessary for ensuring that BP officials and crew abide by standard safety measures. The government did not require



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industry to do negative pressure test which was a major contributor to the Macondo blowout. It is also obvious that regulators failed to ask tougher questions regarding safety because they lacked the skill and technical knowledge for effective supervision.

The oil reservoir contained 110 million barrels of oil (BP, 2010b). MacDonald (2012) indicated that “responders had three options listed in roughly descending order of reliability to estimate the total discharge rate of oil: (1) use technical means – seabed sensors and videos

– to quantify the flow from the discharging jets; (2) model from the geological and engineering data already known about the reservoir and well from the exploration drilling that Deepwater Horizon had completed just before the accident; or (3) quantify the amount of oil arriving at the surface of the ocean, and back-calculate a discharge rate from that.

Eventually, the authorities would come to rely on methods (1) and (2), analyzing video footage from cameras on remotely operated submersible vehicles with a quantitative visual technique called particle imaging velocimetry”. Initially, BP claimed that 1 000 barrels of oil per a day was spewing out from the well. However, this flow rate changed to 5 000 barrels per a day. After extreme public pressure on BP, the flow-rate was estimated at 55 000 barrels per day. Eventually, The Flow Rate Technical Group estimated that the leak initially produced 62 000 barrels of oil a day and eased to 53 000 barrels a day as the reservoir gradually depleted itself. On August 4, 2010, a Federal government document titled, “Oil Budget” provided the government’s first public estimate of the total volume of oil discharged during the spill at roughly 4.9 million barrels (National Commission on BP oil Spill, 2011).

The government arrived at this figure using its current flow-rate estimate, which ranges from 62 200 barrels per a day on April 22 to 52 700 barrels per day on July 14 making it the worst accidental oil discharge in US history (National Commission on Oil Spill 2011).

The true figure was 58 000 barrels a day leaking into the Gulf of Mexico (MacDonald, 2010). Some analysts believe that the uncertainty in judgment about flow rate caused more harm. This explains why a containment dome placed on the riser in May failed. It could not handle the rate of flow and within less than an hour became clogged with gas hydrate ice (MacDonald, 2010). In addition, the “top kill” attempt to plug the well with drilling mud did not succeed because of the enormous pressure of the oil and gas discharge. As a result of the accurate estimates of the flow rate, the responders gained the confidence to unbolt the broken flange and bolt a new closable cap in place to shut off the discharge.

It was only when the Flow Rate Technical Group began to have credible numbers for discharge and reservoir pressure and trends over time that the responders gained the confidence to unbolt the broken flange and bolt a new, closable cap in place to shut



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off the discharge. The oil spill lasted for 86 days and spread across 2 322.576 to 6 317 square kilometre of water (Cleveland, 2010). By the time the Deepwater Horizon well was finally plugged on 15 July, it had spewed some 750 million litres of crude oil into the Gulf (Mascarelli, 2010). The oil spread was not localized as it was moved much faster by strong southern winds and ocean current. BP has recovered about 800 000 barrels, or roughly 17%, during its containment efforts.

5.0.5 Assessment of the Socio-economic Impacts of the Oil Spill

A number of economic activities were hard hit by the oil spill including stocks, oil industry, real estate, tourism industry and commercial fishing. The oil spill resulted in significant losses to investors in the oil industry around the world. Also, BP cut its dividend payments for 2010, and investors turned to alternative companies such as Royal Dutch Shell (BP’s competitor) in order to obtain more profit. At the time the leak was sealed, the spill had resulted in a net loss of approximately $61 billion to BP, $17 billion to partners, $13 billion to the drilling sub-industry, and $19.0 billion to other integrated oil and gas firms (Lee & Garza-Gomez, 2012). Competition effects were also found for firms and sectors of the oil and gas industry not related with BP and/or drilling. The market capitalisation of BP went up and down as more news about the oil spill became public. BP’s market-adjusted loss in value for the entire episode was $61 billion (Lee & Garza-Gomez, 2012).

The Gulf region accounts for about a fifth of the nation’s oyster production and 75 percent of the domestic shrimp output (U.S. Department of Energy, 2006). Louisiana’s seafood industry supplies up to 40 percent of US seafood supply and is the second biggest US seafood harvester. Oystermen witnessed multi-generation family businesses slipped away as the demand for seafood from the Gulf fell as a result of consumer wariness, perceptions and fears of tainted seafood and soiled beaches.

By May 2010, commercial and recreational fishing in Mississippi, Alabama and Louisiana were also affected by the oil spill. Louisiana’s Governor declared a state of emergency on April 29, 2010. Real estate surrounding areas of the Gulf fell to about 10 percent erasing about $4.3 billion in value and job losses could total 1 million over next 5 years. Property owners also lost value on their properties because of the damage from the oil spill. The means of support for oil-rig workers were temporarily derailed by a blanket drilling moratorium, shutting down all deepwater drilling rigs, including those not implicated in the BP spill. Thousands of people whose livelihood depended on tourism or harvesting marine life remain unemployed. It was reported that Louisiana had a 6.2% unemployment rate due to the moratorium. Small businesses like souvenir shops, restaurants, bars and even the priest at the local church in Louisiana filed a business loss claim against BP.



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5.0.6 Health Vulnerabilities of the Oil Spill

The unquestionable trauma of losing colleagues, the terror of the explosions, fires, the harrowing rescue has left indelible imprints on the memories of survivors of the oil rig explosion. “Our people are used to tragedies and pulling themselves up from their bootstraps . . . but no one is saved from depression and fear,” said Sharon Gauthe, Executive Director of Bayou Interfaith Shared Community Organizing. Although many of the behavioral and psychological effects of the oil spill remain unknown, a Gallup survey of nearly 2 600 residents revealed that medical diagnoses of depressive illness in residents of the Gulf region has increased by 25 percent since the rig explosion. Important symptoms include depression, substance abuse, domestic violence, psychological disorders and disruption of family structures (Braud & Kruse, 2009). Psychological effects and depressive illnesses have worsened as issues of fault and compensation are negotiated or litigated over extended periods (Braud & Kruse, 2009). Unfortunately, not all medical conditions are covered. Gulf Coast Compensation Fund has maintained that it will not pay damages for mental illness caused by the oil spill (Arata et al., 2000).

The four classes of hydrocarbons in crude oil are saturates, aromatics, asphaltenes, and resins (Leahy & Colwell 1990); Polycyclic aromatic hydrocarbons (PAHs) have unique structure and bonding and this increase their solubility and, therefore, their ability to influence various enzyme-mediated reactions in biota. Due to their toxic and mutagenic effects, aromatic compounds are the most environmentally significant of all compounds in crude oils (Mendelssohn, 2012). Fresh oil is more toxic than weathered crude oil because the concentration of volatile organic compounds (VOCs) decreases with weathering. Studies have shown that alkyl nitrates, methane, hexane and butane compounds from the oil can irritate or burn skin and eyes or cause dizziness. These chemicals have been associated with miscarriages and damaged airways. The smell of oil causes severe headaches, nausea, respiratory problems, burning eyes and sore throats (Goldenber, 2010). Several clean-up workers who were deploying booms were hospitalized due to respiratory and dermatological health problems believed to be caused by the fumes and odors of evaporating hydrocarbons. Some scientists suggested that the use of chemical dispersants (Corexit EC9527A and Corexit EC9500A) which contain 2-Butoxyethanol, propylene glycol and dioctyl sodium sulfosuccinate could have significant side effect (Bolstad, 2010). Other stakeholders objected the use of these dispersants after 2-butoxyethanol was identified as the agent causing health problems of clean up volunteers which are similar to those experienced by workers involved in the 1989 Exxon Valdez oil spill in Alaska. Corexit 9 500 is currently banned in British waters due to its potential health risks to cleanup workers (Levy & Chennat, 2010). Critics pointed out that BP’s decision to use Corexit was not motivated by factors laid out by BP but by the close business relationship that BP had with its manufacturer Nalco (Bolstad, 2010).



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The negative health and environmental problems of the oil spill increases as the slick is dragged and crept closer to the shoreline. Oil slick along the coastal beaches is an eyesore and this taints the aesthetic and ecological value of beaches.

5.0.7 Environmental Impacts of Oil Spill

The degree of adverse impact of oil on biophysical environments depends on the chemical content of oil. Different hydrocarbons in crude oil are saturates, aromatics, asphaltenes, and resins. Saturates and aromatics generally dominate. Saturate hydrocarbons, which contain straight-chain, branched, and cyclic structures, constitute the greatest percentage of crude oil.

The majority of crude oils encountered in oil spills contain straight-chain hydrocarbon molecules, ranging from single-carbon methane to molecules that contain in excess of 35 carbons, with associated branched and cyclic hydrocarbon structures (Mendelssohn, et al., 2012). Some of the saturate C19–C30 cyclic hydrocarbons are particularly resistant to biodegradation and serve as crude-oil biomarkers. Asphaltenes—large-molecular-weight hydrocarbons containing trace amounts of nickel and vanadium—are even more resistant to microbial degradation and are commonly used as roofing tar and road asphalt (Mendelssohn, et al., 2012).

Identifying and quantifying environmental damages caused by the oil spill, particularly in complex and dynamic ecosystems, present enormous challenges. The National Wildlife

Federation stressed that the full impact of the oil spill on the environment may not be known for months or years to come. Jane Lubchenco, head of the National Oceanic and Atmospheric Administration (NOAA) said they are concerned about the long-term impacts, both on the marshes and the wildlife. Most fishery species spawn in near shore or offshore waters of Gulf of Mexico. Species in their early life stages enter estuaries and use the shallow wetlands therein as nursery and rearing areas. Estuaries within the Mississippi River Delta provide habitat for estuary-dependent species. Nektonic species may be directly exposed to oil when they swim through concentrations of dissolved or suspended petroleum constituents. Oil spill damages gill-breathing animals this imperils respiration. The gill uptake results in a body load of toxins that may have lethal or sub-lethal effects (Whitehead, 2011).

Many vulnerable species have been identified, including oysters, shrimps, blue crab, finfish, blue-fin tuna and dolphins. Pelicans were also affected by oil spill as their feathers become coated in oil when they plunge into water (Figure 2). This limits their ability to fly, and lessens their ability to regulate their body heat.



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Sperm whales and Bryde’s whales are affected by their ability to reach the surface for oxygen in oil-infested waters. Dolphins are endangered because the other species they consume may be contaminated with oil as a result of biomagnification. Long-lived predatory species such as bluefin tuna, swordfish, marlin and wahoos are affected by the oil spill as the toxins accumulate in species at different levels of the food chain (Gohike et al., 2012). On the sea floor, animals that strain food from the water, including tube worms, clams, mussels and barnacles, could also be exposed to oil micro droplets in the ocean. Louisiana’s fragile delta habitats bore the brunt of the damage, with approximately 20 additional miles of Mississippi, Alabama, and Florida shorelines moderately to heavily oiled. Clearly, the use of chemical dispersants will cause long-term alternations of marine ecosystems and threaten several species.

A large number of Atlantic tuna at a major spawning site in the Gulf of Mexico probably fell by at least 20% this year as a result of BP oil spill. The ability of phytoplankton to access sunlight is also affected and this has negative impact on small fish that heavily depends on phytoplankton to survive. Pryosomes die because of hydrocarbons in their tissues and turtles are affected when they ingest pyrosomes. The presence of oil slick prevents seawater from absorbing oxygen from the atmosphere and this threatens countless marine organisms.

Digestion of high amounts of underwater oil plumes and methane by microbial organisms in the gulf’s depths could lead to oxygen depletion.



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5.0.8. Management of the Impact of the Oil Spill

After several failed attempts to cap the well, BP used a procedure called “top kill” and “junk shot”. A top kill—also known as a momentum or dynamic kill—involves pumping heavy drilling mud into the top of the well through the BOP’s choke and kill lines, at rates and pressures high enough to force escaping oil back down the well and into the reservoir (National Commission, 2011). The company initiated what is known as the “Static Kill”, which essentially is pumping the well with mud until the explosion surrounding it is chocked and stops any further leakage. Engineers pumped mud into the well, waited a few days until it dried, and then started plugging the well. The process went smoothly, and BP finished installing the capping stack without incident by July 12, 2010. Well integrity tests were carried out by monitoring pressure, sonar, acoustic, and visual data continuously. The result of test was positive and the static kill was successful.

Following the incident, President Obama requested a 30-day general safety review of installations. On April 26, 2010, he ordered immediate inspections of all deepwater drilling rigs in the Gulf of Mexico, and careful monitoring of work under existing permits to drill. Secondly, on May 6, 2010, he directed the MMS as a temporary measure to stop issuing new offshore drilling permits pending completion of the review of the adequacy of existing safety systems (National Commission, 2011). The USA senator for Louisiana, Mary Landrieu, testified before this Commission that the moratorium was “unnecessary, ill-conceived and has actually created a second economic disaster for the Gulf Coast by putting thousands of jobs at risk and recommended an immediate termination of a prolonged and arbitrary ban on offshore oil and gas development”. Also, based on criticisms from the courts, the Department of the Interior then issued a revised moratorium on July 12, which limited drilling based on the equipment a rig used rather than the depth of the wellhead.

As part of efforts to clean up the oil spill, controlled burn was undertaken and this resulted in release of thick black cloud of smoke into the atmosphere. It has been estimated that only 16% of the oil spill has evaporated or dissipated naturally and 17% has been captured by various oil devices. It is still not known the precise amount of oil that still remains in the Gulf, but researchers believe that about 26% of it is in the Gulf. “Booms” or floating barriers were used on the ocean surface to keep the oil from spreading (Figure 3). Unfortunately, this technique also failed because the rough sea waves prevented the floating protective booms from being in place properly and caused the oil to sweep over the booms. Booms were not enough and competition for boom occurred at the parish and town levels as well. At a press conference in mid-May 2010, Governor Jindal said that the containment boom provided to Louisiana by the Coast Guard and BP was inadequate.



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Several small fires were used to reduce the total amount of oil on the surface. Also, oil covered wetlands can be burned in a way that preserves the roots of plants (Kintisch & Stockstad, 2010). Burning does not remove environmental pollution but rather displaces contaminants from ocean into the atmosphere in the form of nitrogen oxide, carbon monoxide, sulfur dioxide and carbon dioxide which can contribute to acid precipitation, smog problems, greenhouse effect and impact on human health. The U.S. Environmental Protection Agency (EPA) considers ethlybezene, benzene, toluene, and xylene a toxic volatile organic compounds that are released from burning.

BP has also adopted technologies such as the “Sand Shark”. The vehicle works as conveyor belt. The sand shark squeaks and shakes as it moves down the beach, scooping up to 2.4384 metres swath of sand polluted with tiny tar balls. It collects sand, removes any hydrocarbons and then lays the sand back down.

The Louisiana Department of Wildlife and Fisheries and the Department of Health and Hospitals began closing fisheries and oyster grounds in state waters—three miles or less from shore. Some wildlife that was trapped in the oil spill were rescued and rehabilitated. Experts from the US Fish and Wildlife Service, the National Oceanic and Atmospheric Administration, the National Park Service, as well as state agencies, helped BP to identify the most sensitive wildlife habitats and prioritize appropriate



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spill countermeasures such as rescue and rehabilitation (oil removal) as well as prevention of the spread of oil to sensitive wildlife areas. Once captured and transported to rehabilitation centers, each animal was individually tagged recorded, cleaned, medically evaluated and assessed by trained wildlife specialists, given appropriate medication, water and food and then monitored, following certified guidelines. BP estimated that 1 246 birds, 397 sea turtles, three mammals and more than 14 000 sea turtle hatchlings were cared for and released, as of 31 December 2010 (BP, 2010).

5.0.9 Claims and Contingency Plans

The oil spill spurred many civil, criminal investigations and lawsuits against BP and its stakeholders. Many of the lawsuits are class-actions filed in Texas and Florida. Local businesses filed claims, demanding money for the business lost. BP’s own response costs were well in excess of US $2.5 billion, including claims paid and federal costs. It is important to note that the US $20 billion does not represent a cap on BP’s liability.

Insurance coverage disputes also seem inevitable. BP itself is understood to have no external insurance in place for the accident. On May 21, 2010, a number of Lloyd’s of London syndicates brought proceedings in Houston aimed at disallowing a possible claim for US $700 million under a policy held by Transocean. Various shareholder derivative suits and class actions are also under way, on the basis that BP directors breached their fiduciary duties to shareholders by exposing the company to civil and criminal liability.

5.0.10. Conclusion

The oil spill in the Gulf of Mexico is the largest ecological disaster recorded in recent times.

A series of unfortunate events and human error coincided disastrously to cause the rig explosion. Lack of proper inspection and supervision of drilling, cost cutting and quick technical fixes contributed to the disaster. The explosion and subsequent oil spill has left a legacy of toxic pollution that will linger on for many years threatening many already endangered species. For some of the members of the Gulf coast, it will take decades for the effects of contaminated food to be felt in among population as a result of bioaccumulation and bio-magnification of toxins in individuals and along the food chain respectively. Wind systems and ocean currents carried the oil spill far



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beyond the geographical location of well, increasing the scale and coverage of the spill and complicating the cleanup operations.

Although, booms, surface burning, skimming, oil pumps, dispersants, sand sharks techniques were employed, the entire clean-up efforts were carried out in ad-hoc and hotchpotch fashion.

Like the Exxon Valdez oil spill, there is still uncertainty about long-term recovery and viability of ecosystems and species in the Gulf region.

The painful realization is that this rig explosion and overly extended period of the oil spill could have been prevented if proper procedures were followed before, during and after the spill. It is envisaged that lessons learned from this accident will inspire great technological solutions, pragmatic policies and collective will to deal with future accidents effectively and efficiently.

5.0.11. Recommendations

Given the bitter lessons from this oil spill, proper government policies and monitoring mechanisms should be established and well qualified oversight committee should be set up to monitor the operations of oil companies in order to prevent such calamities. The oversight committee should be well trained, properly resourced and adequately funded to carry out effective and efficient supervision of oil drilling. Government environmental laws regarding oil drilling should be made more stringent and individual corporate employees who do not comply with these standards should be liable for criminal negligent charges.

The most nerve-racking part of this disaster is how long it took BP to cap the well. The US government was equally helpless in the face of public outcry. This makes one wonder how and why permits for offshore oil exploration could be granted without prudent scrutiny of procedures for preventing and fixing accidents. Future permit conditions should include regular drills, acquisition of well-tested and workable stand-by technology for fixing broken oil wells. This should be backed by refined protocol, organization and management of accidents.

BP should change its philosophy from ‘command and control’ to ‘cooperation and transparency’. BP needs to be open about its operations and affiliated companies should share information, knowledge and expertise before, during and after crises. There is the need for establishing an independent team of oil rig inspectors which should be made of representatives from industry, government, International Standards Organization (ISO), communities and non-government environmental organizations to undertake regular testing, monitoring and assessment of oil rig operations and offer recommendations where necessary.



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This will provide necessary checks and balances and avoid oversights. BP needs to put safety concerns first before costs because prevention is cheaper than cure.

Careless and ill-conceived short-term cost-cutting measures could result in long-term recurring costs of clean up, claims, property losses etc. It is in the best interest of BP to do the right thing to avert a disaster and uphold its reputation rather than waste billions of dollars on remediation legal battles and reclaiming its image. Given that there were computing and telecommunication system failures prior to the oil rig explosion, BP management should undertake a complete overhaul of their early warning systems in order to install effective monitoring systems with equally efficient and effective back-ups. A well-qualified and dedicated expert should be employed full-time to ensure proper functioning of the safety and communication systems.

5.1 Drilling and Well Risk Assessment

April 20, 2010. Not an ordinary day at the Macondo oil field in the Gulf of Mexico. The investigation of the ‘Deepwater Horizon’ accident found problems of course, but also a great deal of business as usual.

As a result of this and other incidents in the drilling industry, operators, drilling contractors and oversight authorities have increased attention paid to many aspects of well operations. What remains lacking is an integrated framework for risk management during well planning and drilling operations. DNV began this project to address some of the process failures in existing drilling and well risk management.

5.1.1 The Nature of the Risk

Traditional risk management techniques are not well suited to addressing offshore drilling risks. “One reason is that, as you drill, you are constantly changing the basis for your risks and also modifying your risk barriers. Specifically, risks change depending on where you are in the drilling operation or what operation is performed. It is unlike traditional process safety in which you have flow in pipes, leak detection and automated shutdown systems in the event of a leak. Instead, during drilling, you are 100 percent dependent on the driller and the drilling team to shut down the system during a critical scenario. The concept is quite difficult to treat, from a risk consultant’s perspective,” states Håvard Brandt, of DNV’s Drilling & Well Risk Management group.

In sum, present methods for risk management are too generic and fail to identify well specific risks, degraded or weakened well barriers during operations, limitations in the drilling and well technology and system interface challenges during operations. Instead, the focus has been on reducing slips, trips and fall related risks; not on understanding and managing risks related to major accidents. There is a need to



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address risk in a lifecycle perspective, from engineering and design into the operation and execution of the drilling operation.

5.1.2 Operation

Control of large scale accident risk requires understanding the complex interaction between man, technology and organisation. Recent improvements in the industry related to Integrated Operation (IO), and new Information and Communication Technology (ICT), have significantly changed the work processes and increased the complexity related to drilling and well operations. These technological improvements offer significant possibilities for further study and guidance in drilling and well risk assessment, and the promise of more systematic risk management and control.

5.1.3 Challenge

DNV’s project, Drilling and Well Risk Management, called for a new assessment of safety barriers in drilling and well risk, one of the most difficult risk management areas. The 2011 project combined staff in three areas: those with the latest technical knowledge related to the process of drilling and wells; experts on drilling and rig equipment; and staff experts familiar with risk management and systematics. This group of global experts was assembled and workshops conducted between them in Oslo. Meetings were conducted over several days. As a result, a suitable risk management process was developed to identify and address drilling and well risk as it relates to the different phases in a drilling operation.

5.1.4 Details

From a project activity perspective, DNV saw two approaches to this process. First, it was desirable to develop a pilot test case with an oil and gas operator to identify framework contents. Second, support from DNV Houston helped launch a drilling risk framework project as a Joint Industry Project. The scope of work included the mapping and identification of risks, of critical barriers, and of requirements for barrier performance. The communication of barrier conditions was addressed as well as a full review of the technology in use. Quantification of risk reduction was then undertaken, and risk models were used to evaluate alternative design and operational methods. The management of change during operations was also addressed, including interface handling, technology, personnel and processes. Shortcoming and gaps in present drilling operation risk assessment were identified.

The risk framework is being taken to the next level through a new initiative establishing performance standards applicable for drilling operations. Performance standards will be developed on the basis of the risk based barrier management and ‘bow-tie’ models.



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5.1.5 Results

Oil operators and drilling contractors are now coming to DNV for knowledge and support in managing drilling related risks. A suitable risk management process has been developed – one that can identify and address a broad spectrum of risk factors. Companies can use this process not only to evaluate operational risks, but to evaluate the effect of specific risk mitigation actions, operations methods, technology in use and contingency plans. This new process holds the potential to greatly improve drilling safety.

Knowledge and background from the project supported Statoil in implementing their drilling risk management process for the Gullfaks field in Norway. As Brandt notes, “Now, we can systematically work on looking at technology and assess risk of blowout, as well as blowout contingency action plans. Without an integrated approach to this, it’s easy to make wrong decisions.”



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Chapter 6

Financial and Other Risks

6.1 Offshore oil and gas operations: financial liability for all operators

A provisional deal on proposed legislation for the safety of offshore oil and gas operations was struck by MEPs and Council negotiators on Thursday. Before oil and gas firms could get a licence to drill, the directive would require them to submit major hazard reports and emergency response plans and prove their ability to remedy any environmental damage caused.

"Europe learned its lessons from the Deepwater Horizon catastrophe and wants to reduce the risks of offshore oil and gas drilling to a minimum. Especially now that several member states are exploring new drilling operations, we need an efficient legislative framework. The previous directive is nearly 20 years old and does not guarantee the safety of offshore drilling operations in an adequate manner", said Ivo Belet (EPP, BE), who led the negotiations.

This agreement ensures an EU legal framework that will help us to prevent offshore accidents in our seas and ensure rapid intervention which will limit potential damage", said Energy Committee Chair Amalia Sartori (EPP, IT).

6.1.1 Major hazards report and major accident policy

Drilling companies would be required to submit to the national authorities a special report, describing the drilling installation, potential major hazards and special arrangements to protect workers, before starting operations. EU Member states would require operators to prepare a document setting out their "corporate major accident prevention policy" which would guarantee inter alia an open reporting culture for incidents, consultation with elected safety representatives and protection for whistleblowers.

6.1.2 Internal and external emergency response plans

Companies would also have to provide an internal emergency plan, giving a full description of the equipment and resources available, action to be taken in the event of an accident and all arrangements made to limit risks and give the authorities early warning.

At the same time, EU member states would have to prepare external emergency response plans covering all offshore drilling installations within their jurisdiction. These plans would specify the role and financial obligations of drilling companies as well as the roles of relevant authorities and emergency response teams.



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6.1.3 Need for a directive

Although the Commission's initial proposal referred to a "regulation" (which would be directly binding upon all member states), negotiators for Parliament and the Council agreed to recommend adopting a directive (which lays down ends, but leaves means to member states) instead, in order to avoid redrafting existing equivalent national laws.

6.1.4 Application and transposition

Member states with offshore waters that have no offshore oil and gas operations under their jurisdiction, and landlocked countries with companies registered in their territories would need to apply only a limited number of this directive's provisions. Member states would have two years to transpose the directive into their national laws.

6.1.5 Follow Up

The provisionally agreed text which still needs to be adopted formally by COREPER will be put to an Energy Committee vote, probably in March, and then a plenary one in May (provisional timetable).

6.2 Stricter Rules

The European Parliament and Council negotiators worked out a deal, on 21 February, on a draft directive to improve the safety of offshore oil and gas drilling platforms. The text, which still has to be approved by Parliament, spells out conditions for authorising these operations and liability for environmental pollution.

“Europe learned lessons from the Deepwater Horizon disaster and wants to reduce the risks from offshore oil and gas drilling to a minimum. We need an efficient legislative framework, especially now that several member states are exploring new drilling operations. The previous directive is 20 years old and does not guarantee the safety of offshore drilling operations adequately,”

6.2.1 Liability

Although the text approved is less stringent than the Commission’s proposal - the executive suggested a regulation but the text will be a directive, as demanded by the UK in particular - it nevertheless contains important provisions to ensure safer drilling. This is particularly the case for financial liability. The text provides that all operators must guarantee that they have sufficient physical, human and financial resources to minimise and rectify the impact of a major accident. A licence will not be granted unless the applicant can prove that adequate



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provision has been or will be made to cover liabilities potentially arising from its offshore oil and gas activity. The accent is on applicants’ financial capability, so that they can compensate for any economic damage, where such liability is provided for by national law in the country where the operator plans to drill.

6.2.2 Emergency Response Plans

Oil and gas companies will also have to draw up risk analyses and emergency response plans. They will have to submit a special report to the national authorities describing the drilling installation, potential major hazards and special arrangements to protect workers before starting their operations. Operators will have to prepare a document outlining their “corporate major accident prevention policy,” which would guarantee an open reporting culture for incidents, consultation with elected safety representatives and protection for whistle-blowers.

Companies will be obliged to present an emergency response plan describing in detail the equipment and resources available, action to be taken in the event of an accident and all arrangements made to limit risks and give the authorities early warning. Member states will have to draw up external emergency response plans covering all offshore drilling installations in their jurisdiction. These plans would specify the role and financial obligations of drilling companies as well as the roles of the competent authorities and emergency response teams.

6.2.3 Jurisdiction

Member states with offshore waters that have no offshore oil and gas operations under their jurisdiction, and landlocked countries with companies registered in their territory, would need to apply only a limited number of this directive’s provisions.

The provisionally agreed text will be put to the vote in the European Parliament’s Committee on Energy (ITRE) probably in March, and then in plenary in May. Once the directive has been formally adopted, member states will have three years to transpose it into national law.

6.2.4 Reactions

Greenpeace and Oceana regret that no financial compensation for oil spill damages is foreseen for fishermen and tourism operators. Greenpeace also regrets that the European Maritime and Safety Agency (EMSA) will not be given greater powers of supervision and control. The text does not give this authority the possibility to carry out inspections on platforms. The non-governmental organisations criticise the absence of provision for a



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moratorium for drilling in sensitive areas, particularly the North Pole. This question should be discussed in the Arctic Council, since the EU has no rights over these waters, notes the rapporteur.

Oceana applauds the addition of a new risk calculation tool in the prevention system, namely the oil spill response effectiveness tool. “We are pleased that this tool was adopted to objectively quantify time when emergency plans are impeded because of environmental conditions, such as wind, waves, ice or low temperatures,” commented Nicolas Fournier, policy adviser at Oceana. He added: “In certain locations, harsh weather conditions can severely reduce response effectiveness to less than 40%, meaning that six times out of ten no intervention would be possible for cleanup and recovery”.

6.3 Oil Spill Risk Management For Offshore Exploration And Production Oil

Platforms: The Greek Case.

This study attempts to evaluate the worldwide and Greek regime in oil spill preparedness and safety risk management for offshore installations with a view to identifying potential weaknesses and areas of improvement, particularly in Greece. To this end, the current practices and relevant legislation at international, EU and Greek level had to be identified and then to be assessed for their adequacy, particularly in Greece’s case.

6.3.1 Introduction

The Deep Water Horizon accident has given rise to the industry, regulators and other stakeholders needing to review their approach to the management of containment and oil spill risks associated with offshore oil drilling and production activity worldwide. The adequacy of response preparedness has been a matter for considerable discussion, as most current strategies cater for maritime accidents. While with shipping we are dealing with a mobile risk of finite oil spill size i.e. we don’t know where the spill might happen or what type of oil might be, but we do know that the total amount of leaked oil will be limited, with an offshore platform, the situation is the exact reverse. The location of incident and oil type is known but the potential release quantity and duration is unknown. In determining the size basis on which to design the planning and response provisions, risk-based approaches have been already used in oil industry in many countries and could provide the basis for the future development of a universally accepted decision-making tool in the case of offshore oil drilling.

6.3.2 Analysis

A number of international legal instruments have been developed the past years aiming at enhancing oil spill response preparedness. The most important is the OPRC-90 which is ‘owned’ by the IMO. Following the OPRC convention which promoted international cooperation and multilateral agreements among countries, many others have been developed at a regional level with the same target, such as the Barcelona Convention, ‘owned’ by UNEP



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and its protocols. The Offshore Protocol which provides for the safety of offshore drillings is of particular importance but until now it has been ratified by only six Mediterranean countries.

The EU features patchy legislation that covers many aspects of the offshore oil activities but there is no single legal instrument that governs the safety regime of offshore oil drillings in a uniform and holistic approach. However, the European Commission is currently examining this issue in depth and decisions will be made in the near future.

Greece has ratified OPRC-90, Barcelona Convention and most of its relevant protocols apart from the Offshore Protocol. In addition, as an EU member, Greece has ratified the most significant Directives that are applicable to offshore oil industry. There is also a number of relevant national statutes and the National Oil and Noxious Substances Pollution Contingency Plan (NCP) which aims at an effective pollution response and preparedness. However, many weaknesses have been identified and there is a need for an update, as it hasn’t been amended since it entered into force in 2002.

Oil spill response and preparedness can be facilitated with the international tiered system, where each of the three tiers can be defined as a function of spill size and location. Contingency planning is one of the components of an effective and tested management capability and depends on the prevailing environmental and operational factors. Although there is no universally accepted model for determining response preparedness in offshore oil industry, there are various risk-based practices in some countries, including the UK, Australia and Norway which could form the base for similar approaches in other countries. The ‘bow-tie’ analysis, where prevention and response barriers that ‘contain’ a spill event are risk assessed and the outputs are used to determine the appropriate capacity, is a model that can facilitate the formation of an effective preparedness assessment tool for offshore oil industry in the future.

6.3.3 Discussion, Conclusions and Implications

Even though there are a number of practices and regulator’s requirements in relation to oil spill preparedness and safety of offshore installations, it seems that they all failed in the case of Deepwater Blue Horizon case. However, they only provide the ‘vehicle’ for an effective response and it’s up to operators to make all the essential arrangements to deal immediately with an emergency situation and for timely call on additional resources. In addition to that, the efficiency of response depends on the efficiency of both counter response equipment and well containment procedures. The latter is hugely important since no level of preparedness or response capacity will manage to address a prolonged oil release from a drilling well into the marine environment, unless a successful capping operation is carried out.

As for the applicable to offshore drilling risk management practices, their effectiveness will always depend on the quality of risk assessment that has been conducted and the criteria for risk acceptability. In any case, a more risk-based approach rather than a regulator’s



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prescriptive one seems to be a more appropriate solution as operators tend to depend on regulator’s monitoring and prescriptions instead of developing their own safety tools.

Some of the shortcomings and limitations of the current study are outlined below:

� It was not possible to include all worldwide existing legal instruments and risk management practices regarding oil spill response preparedness on offshore oil installations. In particular, some of industry’s practices are considered proprietary rights and are not accessible by the public.

� Most of the described practices and legal tools have been designed for the maritime oil spill risk and bare little consideration on offshore oil platforms.

� As this study was–among other things-the first known attempt to assess oil spill preparedness in Greece, it certainly didn’t cover all aspects and was based purely on the understanding of the current situation.

Consequently, there is a need for further research on safety risk management practices and legal instruments that will better cater offshore oil industry and the associated oil spill preparedness issues. Furthermore, there is a need for further research on oil spill combat techniques and their estimated efficiency in pollution events, as this is a key issue that will better determinate the required response capacity.

The current study would probably provide some insight into oil spill preparedness issues and how those can be related with safety risk assessment on offshore oil installations for various stakeholders including governmental and local authorities, offshore oil industry and the public. Since there is a particular focus on the Greece’s situation, it might be useful to decision-makers that have been assumed the duty of sustaining and improving oil spill preparedness in Greece. In addition, various international oil companies that intend to engage in offshore oil activities on the Greek seas in the near future may find a description of the relevant regulatory framework in Greece.

6.3.4 Recommendations

Some of the recommendations are presented below:

• States could adopt a more risk-based approach and less prescriptive towards HSE of offshore oil installations, allowing ‘self-regulation’ and following the examples of Norway, the UK and Australia;

• Closer industry/government, industry/industry and government/government cooperation on HSE and oil spill preparedness and response issues of offshore oil industry;

• Establishment of better procedures for timely mobilization of resources in case of an escalating pollution event;



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• States need to be assured that offshore oil operators will have the financial capacity to deal with clean-up costs and liability. For this reason, authorities could take into account assets, insurances or other ‘risk-pooling’ instruments;

• The EU could examine the possibility of closer cooperation with non-EU Mediterranean countries on the safety of offshore industry, as it is likely that a major pollution event will affect EU Mediterranean countries;

• Countries could allow public participation and review of corporation pollution plans.

• Updating the Greek NCP taking into account other NCPs of more advanced countries like Norway and the currently perceived risks in the Greek waters. NCP could include requirements for the offshore operators regarding Worst Case Discharge, mobilization of response and containment of a well in case of blow-out;

• Establishing a decision-making tool for timely approval of dispersants, as an integral part of the Greek NCP.



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Chapter 7

The Indian Scenario

7.1 India's Unfavourable Climate in Oil & Gas

About 93% of India's energy comes from fossil fuels and Oil and Gas accounts for about 43% of the total energy produced from the same. Of this 43%, a large part comprises of imports of oil and gas which has created an uncomfortable situation for a large developing economy like ours. Over the last decade, increasing the domestic production and encouraging exploration has been a focus area. Nonetheless, the oil and gas reserves of the country remain largely unexplored, primarily due to huge capital requirements.

Exploration and production of Oil and Gas is a risky proposition where the inputs are generally deterministic, relatively independent of the quality and quantity of reserves. On the other hand, outputs are probabilistic, subject to probability of finding reserves of suitable quality. Therefore, only an attractive investment regime can attract domestic as well as foreign investor's risk capital to India. Domestic players lag behind, and poor prospect from profitability point of view has made foreign players apprehensive. An investor-friendly climate can only be created if regulatory bodies ensure reasonable returns and relatively risk-free environment to operate.

With the New Exploration Licensing Policy (NELP), a major thrust was given to bring in the much needed capital and state-of-the-art technology to the exploration sector.

It was aimed to create an investor-friendly climate and was marked by attractive fiscal and contractual features. The policy also addressed the underground risks involved in exploration of sedimentary basin. However, risks over the ground, mainly due to policy inaction and unfavourable investment climate have made investors wary.

Over a period of time, what we now observe is that not only the underground risks remain as it is, except for few excellent discoveries, but the above aground environment has also not improved much."

Political uncertainty, frequent changes in policy and stricter policy controls have already made the foreign investors apprehensive about India. If not addressed immediately, these would also start affecting the domestic players in next few years.

India has not been able to create a regulatory or an incentive regime in the government's public-private partnership (PPP) model.



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Being a highly regulated sector until recently, the government has also not done enough to facilitate PPP in this segment and has not been able to attract private oil and gas exploration companies in tapping new blocks.

The crux of India's energy security challenge lies in pricing. Price regulations have limited the attractiveness of the sector. Distortion in pricing have waned the investor sentiment. Moreover, lower prices have resulted in little or no demand-discipline on consumer side, which contributes to a huge wastage of power. Higher gas prices are a necessity for the sector. Unless higher prices are given to the producers, private sector investors will not invest.

Further, subsidies provided to sensitive petroleum sector contradicts the freedom granted to companies under Administered Pricing Mechanism. There appears to be a wide gap between the objectives, policy and implementation, especially for Oil and Gas in India.

If India has administered price mechanism, which does not take into account the need for ensuring that there should be adequate returns, then obviously expectation that foreign capital will come in or foreign private capital will invest is I think a pipe dream,

Government attempts to micro-regulate the sector, specifically production and exploration, are unlikely to be successful due to lack of institutional capacities to support such intents. The process involves 60+ licenses to be acquired - a cumbersome and costly process in terms of time and money. This is a major drawback in India's investment climate and a major hindrance in attracting foreign investment.

Given the grim outlook, policymakers need to make timely decisions in order to avoid impending policy paralysis. Failure to do so would result in a serious crisis in the power sector in near future. Government should maximise energy production and focus on energy security rather than maximizing revenues.

One cannot afford to have policy paralysis for a day longer. Next time a crisis hits India, the payoff will be so enormous that India will not be able to come out of it as simply and as quickly as it came out in 1991.

7.2 Exploration Risk Management in Indian PSUs: OIL

7.2.1 Introduction

Oil India Ltd. (OIL) has been playing an important role to meet the energy requirements of the country. The rising population and the consequent increase in demands of petroleum products have put a lot of pressure on OIL. Despite the best effort of different petroleum companies and OIL, the country has to import oil from the international market. The Government of India gives emphasis for the exploration activity. It is expected that the continuing initiative for exploration by OIL in the MNONN-2000/1 block of Mahanadi Basin will meet the challenge partially.



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If MN-ONN-2000/1 block is successful, it will ease the pressure to some extent, on the nation to import crude oil. At present, India’s demand for petroleum products is growing at a rapid rate and it would reach a level of 155 MMT by 2006-2007. With a view to meet this growing demand, the exploration activities are accelerated on land as well as in deep waters. Considering the current demand and supply, the level of self-sufficiency is likely to decline to about 30% over the next few years. Therefore, substantial efforts are needed to boost the level of exploration activity so that new finds can be made and the production of crude oil & gas can be significantly raised in the years to come.

Oil India Ltd. (OIL) along with its Joint Venture Partners viz. ONGC, GAIL & IOC has been awarded an exploration block MN-ONN-2000/1 in Mahanadi Basin of Orissa State under New Exploration Licensing Policy (NELP) of the Government of India. In support of the long-term hydrocarbon exploration program, OIL intends to drill one exploration well within the Block.

Further exploratory drilling may be performed depending on the results of the initial drilling program and on the results of other geological evidences in the block.

7.2.2 Project Setting

Block (MN-ONN-2000/1) falls within the Mahanadi Basin of Orissa and encompasses an area of 7900 sq. km. The block includes a major township in Cuttack district located on the Kolkata-Bhubaneshwar highway in Orissa.

This circle block extends from west of Kendupatana and east of Katikata village. Sadhupur village is 7 km away village Katikata. Nemalo village is in southwest direction from well location Sadhupur. The block falls partly in the Orissa tectonic block and mainly in the Mahanadi Basin.

7.2.3 Objectives of Risk Assessment Study

The objectives of the Risk Assessment are as follows:

♦ Identification of vulnerable zones in the drilling area

♦ Estimation of hazard distances for the Maximum Credible Accident scenarios

♦ Suggestions for risk mitigation measures and delineation of approach to Disaster Management Plan (DMP)

7.2.4 Scope of Work

The scope of the present report is to carry out risk assessment of offshore well. Standard industry practices of risk assessment were considered in the project. The hazard potential of various fuels/chemicals and estimation of consequences in case of accidental release are the issues of immediate relevance to be considered. It is therefore, imperative to carry out MCA analysis (termed as Rapid Risk Assessment) at the first stage, which identifies vulnerable areas of the facility and suggests a set of recommendations for improved safety.



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Oil India Limited, (OIL) retained National Environmental Engineering Research Institute (NEERI), Nagpur to undertake Risk Assessment Study for their proposed offshore wells.

The work undertaken consists of the following stages:

♦ Collection of relevant data on well

♦ Damage distance computations

Maximum Credible Accident analysis is carried out to arrive at the hazard distance for the worst case scenario. The consequences of all the scenarios are computed and hazard distances are worked out and listed for flammable materials and possible explosion effects.

Risk mitigation measures, based on MCA analysis and engineering judgements are suggested in order to improve overall system safety.

7.2.5 Drilling Process

Drilling of oil / gas wells employs mobile drilling rig. The drilling rig consists of a derrick at the top of which is mounted a crown block. A hoisting block having a hook is suspended from the crown block and a swivel is attached to the hosting block by its shackle. From the swivel a tube of square section is suspended, which is called “kelly stem”. The kelly stem is passed through a square hole in horizontal rotary table which is driven by electric motor.

7.2.6 Exploration Plan for MN-ONN-2000/1 Block

Oil India Ltd. (OIL) alongwith its Joint Venture Partners viz. ONGC, GAIL & IOC has been awarded an exploration block MN-ONN-2000/1 in Mahanadi Basin of Orissa State under NELP-II. None of these locations occur within the coastal regulatory zone. Final well locations within these polygons has been selected & stacked by the operator. In general the wells will be located avoiding dwellings, minimizing interferences with agricultural activities, community infrastructure and avoiding disturbances to forested lands and otherwise sensitive or unique habitats.

Habitat with potential to support flora and fauna (including fisheries) with special conservation status or of local socio-economic importance shall be avoided.

The well shall be logged and proposed to be drill stem tested. Water based drilling mud will be used. If potential oil and or gas reserves are observed then the well shall be cased with production casing. After confirming casing integrity and cement bonding, the well shall be temporarily abandoned for future completions.

Depending on the success of exploratory drilling program and results of other geoscientific evidences OIL may seek permits to drill additional exploration wells within this Block. In the event of commercial discovery it is expected that OIL would proceed with planning and application for approval to construct potential pipeline and hydrocarbon processing facilities though the exact nature and location of these facilities cannot be predicted at present.



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7.2.7 Maximum Credible Accident Analysis

MCA stands for Maximum Credible Accident or in other words, an accident with maximum damage distance, which is believed to be probable. MCA analysis does not include quantification of the probability of occurrence of an accident. In practice, the selection of accident scenarios for MCA analysis is carried out on the basis of engineering judgement and past accident analysis.

7.2.8 Consequence Analysis

Quantification of the damage can be done by means of various models, which can then be translated in terms of injuries and damage to the exposed population and buildings.

Oil and gas may be released and result into jet fire & less likely unconfined vapour cloud explosion causing possible damage to the surrounding areas. The extent of the damage depends upon the nature of the release. The release of flammable material and subsequent ignition results in heat radiation, pressure wave or vapour cloud depending upon the flammability and its physical state.

7.2.9 Results and Discussions

7.2.9.1 Consequence Analysis of Wells

Accidental scenarios visualised for the consequence analysis of wells considering operating pressures greater than atmospheric are jet fire for well blowout scenario.

7.2.9.2 Well Blowout

The release of well fluid due to well blowout can lead to a jet fire if the released gas ignites immediately since the operating pressure is very high. Length of jet flame and heat load generated by the flame depends upon the mass flow rate of released material.

The damage distances due to well blowout are computed for the hole diameter of 26’’. The damage distance for heat load of 4 kW/m^2 as 1051.02m, 1015.54m and 978.40m for stability class 2F, 3D and 5D respectively. Similarly, the damage distances for 12.5 kW/m^2, and 37.5 kW/m2 were also computed.

7.2.10 Risk Mitigation Measures

7.2.10.1 Risks to Personnel

Risks to Personnel

Good safety management, strict adherence to safety management procedures and competency assurance will reduce the risk. Safety practices are needed to carry out jobs safely and without causing any injury to self, colleagues and system.

For total safety of any operation, each team member must religiously follow the safety practices / procedures pertaining to respective operational area. If every team member starts working with this attitude, zero accident rate is not a distant dream.



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Any operation is a team effort and its success depends upon the sincerity, efficiency & motivation of all team members. Safety in such operations is not a duty of a single person, but it is everyone's job.

Use of protective fireproof clothing and escape respirators will reduce the risk of being seriously burnt. In addition, adequate fire fighting facilities and first aid facilities should be provided, in case of any emergency.

7.2.11 Specific Recommendations

7.2.11.1 Wells

♦ Proper insulating joints should be provided on well head

♦ Co-ordination with local authorities, such as port, police, fire, ambulance, nearby industries should be ensured to meet any eventuality

♦ The well should be physically inspected regularly

7.2.12 Disaster Management Plan

Some of the major disasters occurred at Bhopal, Mexico and other parts of the World in last few decades, have made people all over the world concerned about the dangers of chemical accidents. Occurrence of such accidents makes it essential for the Central and State Government agencies as well as the local authorities to be prepared to help mitigate the sufferings and assist during eventualities resulting from any unfortunate occurrence of chemical accident.

7.2.13 Objectives of Disaster Management Plan

In order to be ready to face adverse effects of accidents caused by hazardous substances, a Disaster Management Plan (DMP) will be prepared, as required under the Acts and Rules (Manual on Emergency Preparedness for Chemical Hazards, MoEF New Delhi). This will be prepared prior to commissioning of sections and approval of competent authority. Similarly an Emergency Preparedness Plan will be formulated and approval of competent authority will be obtained prior to commissioning of facilities.

7.2.14 Disaster Management Plan: Key Elements

Following are the key elements of any Disaster Management Plan:

♦ Basis of the plan

♦ Accident prevention procedures/measures

♦ Accident/emergency response planning procedures

♦ Recovery procedure



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7.2.15 Approach to Disaster Management Plan

“Disaster" is an extremely rare major emergency / accident having high potential which can cause damage to human life / property arising suddenly either due to natural causes or due to human activities. It is necessary to foresee the possible hazardous situation and be in a state of readiness to prevent / minimize the adverse effects.

This includes recommendation on:

♦ Accident prevention procedures

♦ Response system

♦ Safety awareness

♦ Fire fighting system.

7.3 Unconventional risks

A new kid has come to the neighbourhood, and it is time we took notice of him. He claims good things, but has potential for a lot of bad. The new kid is shale gas and oil.

These are a part of what is known as 'unconventional' gas and crude resources. They are not different from regular gas and oil, but are found in different and difficult environments. While shale oil and gas have been around for decades, recent technological advances have made their extraction commercially feasible, and there is considerable excitement around their potential for industry in the next few decades.

Several countries have taken up exploitation of shale gas in earnest. The leader in this has been USA. According to the Energy Department of the US Government, shale gas has been a game changer in that country, with domestic dry shale gas production increasing dramatically from 1 trillion cubic feet (tcf) in 2006 to 5 tcf in 2010 - about 23 per cent of total U.S. dry gas production.

In India too, there has been some activity in the last few years, which has culminated with the Ministry of Petroleum and Natural Gas (MoPNG) of the Government of India making public in August 2012 its Draft Policy for Exploration and Exploitation of Shale Oil and Gas. MoPNG also invited comments from all stakeholders on the policy. The draft policy signals the intention of the Government to go ahead in a serious way in exploitation of the shale gas and oil resources of the country.

The draft policy mentions that the Indian Government entered into a MoU with the United States Geological Survey (USGS) to conduct an assessment of the shale gas resources, and in a study done by the USGS in 2011-12, "technically recoverable resource of 6.1 TCF has been estimated in 3 out of 26 sedimentary basins in India." To put this in perspective, the total



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estimated reserves of natural gas in India on 31 March 2011 were about 1.240 trillion cubic meters, which is around 43.4 tcf. As more basins are still to be explored, the MoPNG is hopeful of the shale gas resource figures going up further.

7.3.1 Implications

However, shale gas and oil exploitation have been stated to have serious environmental consequences, notably on water resources. This is reflected in the fact that the main components of the draft policy include, along with the various issues associated with inviting private players for exploring and exploiting the shale resources (incentives, fiscal and contractual issues, bidding and approval processes) measures relating to water management. This article focuses on highlighting the risks related to water resources from activities of shale oil and gas exploration and exploitation.

The draft policy defines shale gas as "... natural gas generated in-situ and retained in Shale matrix storage, adsorbed onto organic particles, or within fractures in shales of source rock origin and obtained there form through boreholes".

Shale formations have low permeability. The method of recovering the gas trapped in the shale consists of creating artificial fractures in the rock to allow the gas to escape. As these fractures are created using large amounts of pressurized water, it is called as hydraulic fracturing or fracking. The International Energy Agency describes fracking thus: "large volumes of water (mixed with some sand and chemicals) are injected underground under high pressure to create cracks in the rock which remain open. This frees the trapped gas allowing it to flow into the well bore so it can be produced."

"Another key technology is horizontal drilling which enables the well to penetrate significantly more rock in this gas-bearing strata, increasing the chances of gas being able to flow into the well," the agency adds.

As is clear, the process requires large quantities of water. This has serious implications for the water resources of the shale gas areas, including on other existing and proposed uses. The draft policy states that 11,000-15,000 cubic meters of water will be required per well (11-15 million litres), but does not indicate if this is one-time use or if it has to be repeated several times during the life of the well, nor does it state what it the expected gas output per well, so that figures for water needed per unit of gas can be estimated. However, the policy does agree that the volumes of water required are large.

What is of equal concern is that the water, after fracking, flows back to the surface. As the draft policy indicates, this water can have high levels of total dissolved solids and other contaminants. These contaminants can be from the chemicals that are added for the fracking (often many of these are secret ingredients) or those picked up from residues in the shale. This may also lead to the contamination of the surface and sub-surface aquifers.



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7.3.2 Environmental issues

Despite the seriousness of the likely impacts on environment, and particularly on the water resources, the draft policy does not give it the required consideration. The measures proposed for managing water are placed in the annexure, and not in the main policy - and this is itself an indication of the low priority given to them.

Moreover, the measures proposed are essentially non-measures. It is proposed to make mandatory a baseline study of water and air quality in shale gas projects, but this is already required in Environmental Impact Assessments. It is also specified that "river rain (sic) or non-potable groundwater alone should be used for hydro-fracturing jobs." It is not clear how using river and rain water for fracking can be a measure to safeguard local water resources and water uses. Even worse, this condition is rendered toothless by prefixing it with the words "as far as possible". Another problem is if groundwater is used for fracking purposes, this could have serious impact on local aquifers. The measures also mandate rainwater harvesting in some part of the block, and re-use and recycle as the preferred (but not compulsory) way of water management.

The draft policy admits "that there are no specific provisions as on date relating to regulation of the process of hydraulic fracturing, and water injection process as has been provided in ... the USA", but then justifies this by saying that "the Water (Prevention and Control of Pollution) Act 1974, has stringent provisions to regulate/prohibit disposal of polluting matters into water streams/wells (section 24-25)." Anyone who has seen the situation of water pollution control in India, and the effectiveness of these "stringent provisions" would find this assertion laughable.

In fact, the draft policy should have actually recommended formulation of provisions to address the requirements specific to shale gas mining, including to fracking, and even listed some of these provisions. The consideration given to these issues is in stark contrast to the detailed attention given to issues of finance, bidding and attracting private players for exploration and exploitation of shale gas and oil resources.

One reason why the environmental impacts could be very serious is that significant parts of shale gas resources may be in water-scarce areas like Kutch and Rajasthan, or in ecologically sensitive areas like the Himalayas and the western and eastern ghats. Last, but not the least, as fracking projects have mushroomed in America, there have been concerns raised that fracking may trigger seismic activity. However, the draft policy has not even mentioned this issue.



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7.3.3 Implications

Given this background, it is imperative before proceeding with shale gas exploration and exploitation to ensure that environmental and social safeguards are properly in place. These would include amending the EIA notification, 2006 to mandate all shale gas and oil related activity to require prior environmental clearance; mandatory disclosure of all the chemicals used in fracking; carrying-capacity studies of shale areas, particularly the water resources in the region, by independent and credible agencies; mandatory consent of the gram sabhas in exploration and exploitation, and a ban on shale gas and oil mining in ecologically sensitive areas and catchment areas for drinking water sources.

Moreover, since the shale gas and oil exploration and exploitation are new processes, their initiation must be preceded by wide-spread debate and discussions. This should include making public and giving adequate publicity to the regions and areas that are likely to be shale oil/gas bearing, initiating discussions with the local communities on the likely impacts in the areas, sharing the experiences from countries where such explorations are already taking place (e.g. in the US), experiences not only of the positive and negative impacts but also of the kind of safeguards that have been put in place.

The policy for shale gas and oil exploration and exploitation must take into consideration all of these issues with the seriousness they deserve and not make the same mistake that has been made with other natural resource exploitation, namely, riding roughshod over serious social and environmental concerns.



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7.4 Issues in oil exploration

In the current fiscal year, private sector oil and gas companies witnessed significant challenges largely driven by the Comptroller and Auditor General's (CAG) audits and a large number of disputes between the contractors and the Government. In the early 90s, when India faced an acute shortage of oil and gas resources, the Government decided to open the exploration and production (E&P) business to private companies. The overall business model under the New Exploration Licensing Policy (NELP) was to be controlled by way of a production sharing contract (PSC), to which the contractors are bound. PSC is a detailed document which governs the entire business structure for the contractor and protects the interest of Government, the owner of natural resources. Key aspects of the exploration and production (E&P) business such as the contractor's role and responsibilities, procedural aspects, cost and revenue sharing, routine regulatory filings to be made by contractor, etc., are defined under the PSC. It has been argued that PSCs signed in the early years were more loosely drafted and favoured private sector contractors, leading to several disputes between the Government and contractors. PSCs executed in later years, primarily after 2005, were redrafted by the Government to clear loopholes. However, these were seen as ‘highly regulated' by private and independent players, and impacted the response to the NELP-8 auctions held in 2009.

7.4.1 Dispute Areas One of the critical aspects of the PSC, which also tends to be one of the most contentious, relates to cost recovery: the extent of cost recoverable by the operator from revenue generated in the oil and gas field. Another important area of dispute is the investment multiple (IM) that determines profit sharing between the Government and the contractor. In the last two to three years, India has seen a large number of disputes between the private contractors and the Government, most of them around cost recovery claims of contractors and IM. There are three critical issues that have caused disputes between the Government and private contractors. The first issue is cost recovery limits (CRL). Every PSC defines the limit for the contractor. This limit is the overall threshold for contractors to spend and recover costs from petroleum revenues. This limit excludes certain specific cost categories and cost escalation scenarios. It has been argued that CRL has not been clearly defined, and, thus, often leads to a dispute.



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The immediate need is to clearly define the costs recoverable and non-recoverable; also, the issue of limits and change scenarios need more clarity. Additional development cost is another issue. The E&P business comes along with several uncertainties that occur during evaluating the projected output from fields and planning the development cost. Historically, almost all PSCs have seen cases where contractors have submitted revised development plans for additional capex activities. According to the contractor, the additional cost is considered a logical increase to sustain or increase production volumes. These additional developmental costs lead to regular disputes between the contractor and the Government, since the latter tends to consider such cost as part of the original plan and subject to initial cost recovery limits, whereas the former perceives it as additional cost that is required and is recoverable from revenues. A logical conclusion to such disputes would be relying on experts in the oil and gas industry to justify whether the additional cost is required or not.

7.4.2 CAG's scope The last issue is that of audit rights. Private contractors have been regularly raising their voice against the Government auditor going beyond its scope during audits. Contractors insist that the role of auditors is limited to the financial aspects. Recently, the audit reports have seen issues of operational efficiency being raised strongly. The Government needs to clear terms on the scope of audit and to facilitate availability of petrochemical experts if audit needs to include operational and technical aspects. It has been regularly commented that the disputed actions taken by contractors has led to revenue loss for the Government. On the other hand, contractors have been raising issues of delays in recovering billions of dollars they have invested in projects. The future of E&P business in India and the investment by multinationals and Indian corporates would depend upon the extent to which the Government can simplify the NELP process and PSCs. The investment climate would be positive if the private sector feels that their investment would be safe and free of disputes on a long-term basis. On the other side, the Government would feel comfortable in relaxing the rules and regulations, if corporates can demonstrate highest standards of efficiency in various deals. It would be beneficial for both the parties to arrive at a common point on PSC interpretation and managing the project cost. This would need a strong effort from the Government by way of simplifying the rules and regulations around operations of private contractors — such as approving the additional



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development expenditures by way of the standard approach which would involve third-party techno-commercial experts. Similarly, the corporates would have to ensure that they demonstrate strong project management skills at lowest possible cost.



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Chapter 8

Pipeline Protection- New Age Technologies

8.1 Secure Pipe

Designed to protect oil/gas/liquid pipelines against TPI (Third Party Interference) including illegal tapping and unauthorised excavation by providing valuable early warning of these TPI activities.

• A single system protects up to 40km of buried pipeline in real time

• Locate a TPI or tapping event to within 150 metres

• Network multiple systems for longer pipelines

• Very high rates of detection - >95%

• Very low nuisance alarm rates - <3%

• Uniform distributed fibre optic sensor

• No electronics or power in the field

• Intrinsically safe

Refined as a result of joint programs involving European Gas Research Institute (GERG) and NYSEARCH, the research organisation within the Northeast Gas Association (NGA) in the USA

8.1.1 Applications

• High risk pipelines, Crude Oil pipelines,

• Refined product lines – gasoline, aviation fuel, chemicals etc.

• Gas pipelines, Underground power, Drinking water



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8.1.2 Specifications

8.1.3 Installation Overview

Appendix 3

8.1.4 Case Studies

NYSEARCH (USA) – The Office of Pipeline Safety (OPS) identified that the majority of pipeline incidents are caused by “damage by outside force”. Property damages alone for over 300,000 miles of transmission pipe in the U.S. can cost operators millions of dollars annually. This being a high priority area, NYSEARCH installed an FFT Secure Pipe™ system in 2003 along a high pressure gas pipeline at a test site in New Jersey, USA.

Client Quote: “The PSE&G test site in New Jersey has been in place for over two years and has experienced many field tests using many types of excavating equipment. During that time, FFT has been able to resolve all site and system related problems, to the point, where the system is providing reliable and accurate locate data (well within 150 meters). We believe that the PSE&G site offers a wide range of diversity including soft and rocky soils, trafficked roadways, residential/commercial districts, unusually deep HDD sections and is probably one



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of the most difficult and challenging sites that Secure Pipe will encounter. To date, no nuisance alarms have been produced by nearby excavating equipment. Yet the system sensitivity is such that many alarms recorded are caused by pipeline survey and other vehicles driving over the cable. NYSEARCH believes that this technology is critical to safe guard our pipelines and to assure the integrity of our natural gas pipelines”.

NYSEARCH and FFT are currently testing at their second test site, on a Questar pipeline located in Salt Lake City, Utah, and continuing to develop signature recognition software for excavating equipment for future Secure Pipe systems.

The Client Quotes: “Secure Pipe is the only underground sensing technology, currently available, that has the potential to sense the existence of nearby excavators without impacting or damaging the cable. There are several advantages to this technology such as:

1) Ability to detect quasi-static, dynamic and transient events. 2) Ability to provide and alarm and location of event or impact. 3) Alarms are generated without contacting or damaging the cable. 4) Ability to tune and de-tune the system for different environments and disturbances. 5) Flexible settings and user interfaces to help eliminate unwanted alarms. This technology has the potential to dramatically improve safety and help assure pipeline throughput, by minimizing risks associated with third party impacts. By installing Secure Pipe technology, or systems like it, on critical supply pipelines, overall safety will improve and provide an added level of security for all pipeline operators”.

British Petroleum (Europe) – Had a requirement for a third party intrusion detection system along sections of a 1,700km crude oil pipeline that passed through a number of mineral spring areas. Any sort of pipeline damage leading to a crude oil leak would have a catastrophic effect on both the environment and the revenue created from selling the pristine mineral water, so pipeline protection was mandatory. FFT Secure Pipe™ has been installed on the most critical sections first, with plans to roll the system out to additional pipeline sections over the next few years. Being able to utilise the existing fibre optic communications cable already installed alongside the pipeline makes Secure Pipe an extremely cost effective solution for long distance pipelines such as this.

Asian Natural Gas company – in a highly populated country, they needed a way of monitoring main Natural Gas pipelines against accidental damage by earthmoving and construction equipment to eliminate potentially catastrophic accidents. They ran extensive tests on the FFT Secure Pipe™ system, and concluded that the system not only did everything FFT said it would do, but they were getting location accuracies considerably better than the published specifications! Secure Pipe is being progressively implemented across the country.

A global oil company’s Asian operations needed a system to detect and locate earthquakes and landslides along a crude oil pipeline so that action could be taken to shut down the flow



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before any major environmental impact could take place. The system was installed in 1999, and within weeks detected and gave the location of a major landslide so that the pipeline could be shut down and inspected. This system is still in operation today, running 365 days a year in real-time.

European Natural Gas company #1 – Pipeline monitoring 30km of main gas pipeline against intrusions and third party interference. A single Secure Pipe system was installed in 2003, meeting all of the customers’ expectations and requirements. The system was delivered on time, commissioned on time, and they have experienced no failures or problems since acceptance.

European Natural Gas company #2 – Due to a number of recent incidences throughout Europe, the Government mandated that any new high pressure main gas pipelines must have some sort of detection or protection systems to prevent accidental damage or Third Party Interference (TPI) causing a major explosion and the subsequent loss of life and property damage. The options for their new pipeline were to cover it with a cement slab or have an active solution such as FFT Secure Pipe™. Even including the supply and installation of the sensor cable, Secure Pipe was only a fraction of the cost of any alternative options, yet provided pinpoint location accuracy over the entire pipeline, in real time.

8.1.5 How it Works

Appendix 4

8.2 Acoustic Fibre Optic Pipeline Security System

The protection of both land based and sub-aqua pipelines against sabotage, illegal tapping, and terrorist action, etc, is a high priority in all countries, particularly in times of heightened tension; however, until now this has been notoriously difficult to achieve effectively.

When a pipeline is damaged significant revenues will be lost, damage is caused to the local environment and the leakage is a potential hazard to the local population. Often the damage may not become apparent to the pipeline operators for days or even weeks and then it may take days to accurately pinpoint the location of the damage.

Not only must any system be able to provide a high probability of detection with a very low probability of false alarm activations but with pipelines extending over hundreds, if not thousands, of miles, the ability to pinpoint the location of any incident is also a vital requirement if loss is to be avoided or minimized.



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Westminster offer a range of solutions that can be used to provide a high degree of protection to pipelines and terminals and which can be networked and interfaced with other systems to provide a common control and command system covering the whole infrastructure.

Westminster's pipeline protection systems are designed to protect Gas, Oil and Liquid Pipelines and other utility pipeline distribution networks.

8.2.1 Land Based Systems

Most pipelines will be a combination of both underground (buried) systems and overground (exposed) systems and Westminster's land based detection systems will provide protection to both.

8.2.2 Sub-Aqua Systems

Pipelines from offshore facilities or running between land masses are uniquely vulnerable from covert attack from divers and submersibles and present a challenge to adequately protect with the same level of requirement as for land based systems i.e. rapid and sure detection, low risk of false alerts and pin point accuracy in location of any incident.

Fortunately, Westminster can supply a range of advanced sub-aqua sonar systems which can be installed at strategic positions along the pipeline and are capable of detecting and tracking a diver with a close breathing system (combat diver) at up to 700 meters and a diver with an open breathing system at up to 1 kilometre. Diver delivery vehicles (SDV) and small craft will be detected at far greater distances - please see diagram below.

8.2.3 Intruder & Third Party Interference (TPI) Detection

FOPSS2 Fibre Optic Pipeline Security System The Westminster FOPSS2 Fibre Optic Pipeline Security System (FOPSS2) is designed to protect gas, oil and liquid pipelines and other utility pipeline distribution networks by providing an early warning of an attack so that damage can be prevented or minimised.

8.2.3.1 Acoustic Fibre Optic Pipeline Security System

Preventing or detecting leaks caused by corrosion, environmental or malicious damage is a major challenge to pipeline operators faced with ever tighter regulations worldwide.

Where pipelines run through sensitive areas or over long distances in remote, hostile territory, conventional monitoring and protection methods can be stretched beyond effective limits.

If a pipeline is damaged significant revenues will be lost, damage may also be caused to the local environment and the leakage could be a potential danger to the local population. More importantly a terrorist attack on an unprotected utility pipeline could have catastrophic



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consequences.

The Westminster Acoustic Fibre Optic Pipeline Security System (AFOPSS) is designed to protect gas, oil and other utility pipeline distribution networks and their remote facilities by providing an early warning of leaks, illegal taps, excavations and intruders which could pose a potential threat.

AFOPSS will monitor vibration and acoustics at every metre of a pipeline with a single standard communication optical fibre sensor linked to one or more interrogator units.

AFOPSS unique sensing solution will provide security and monitoring, detecting third party interference (TPI) tampering and illegal tapping attempts to within 1 metre along the pipeline.

AFOPSS un-rivalled sensitivity means the sensor can detect analyse and locate leaks or potential threats instantly, regardless of distance.

AFOPSS will alert you with accurate (GPS / GIS) location and intelligent event analysis in time to mitigate the risk from leakage or threats such as digging, landslides, drilling, hot tapping or attempted sabotage. The consequences of a pipeline failure mean that for a responsible business, integrity assurance and risk mitigation is mandatory.

AFOPSS enables pipeline operators to overcome many of the constraints of conventional systems, with AFOPSS you can:-

• One system can cover up 50km of pipeline;

• Simultaneously monitor every metre of a pipeline of any length 24/7;

• Immediately detect and locate leaks or threats to 1 metre accuracy;

• Differentiate multiple events down to 2 metre resolution;

• Track potential attackers in vehicles or on foot;



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• Identify real threats and avoid false alarms;

• Detect and track direction and speed of vehicle movements or even footsteps;

• Minimal false alarms due to event recognition;

• Interface to GIS systems to rapidly show event location;

• Report alarms to controls rooms, websites, text and PDA;

• Remotely configure, manage and upgrade interrogator;

• Low maintenance and resilient sensor;

• It can utilise an existing fibre optic communications cable as the sensor, dramatically reducing the installation cost;

• PIG's can be monitored in real time though a pipeline;

• Detect leaks in real time;

• Provide perimeter intrusion detection around pipeline facility buildings;

• Provide plant monitoring facilities.

8.2.3.2 Unrivalled Acoustic Surveillance for any Length of Pipeline in any Situation

The AFOPSS unit analyses the back-scatter of pulsed laser light from a standard optical fibre cable (often already in place for SCADA or communications) to provide unrivalled monitoring sensitivity for up to 50 km of pipeline per unit.

By linking multiple units the system can monitor hundreds, even thousands of kilometres from a single location.

8.2.3.3 Monitor, Identify and Alert; Minimise False Alarms

The AFOPSS sensor typically detects personnel activity at 15 metres and vehicle movement at 40 metres either side of the sensor fibre.

The AFOPSS system recognises potentially critical events such as excavation, drilling or cutting near pipelines while ignoring background environmental noise thus minimising false alarms.

AFOPSS dynamically tracks vehicles or footsteps, and reports precise location, speed and direction of travel, enabling rapid engagement by security systems and personnel.

The graphical user interface for monitoring and alarming is simple, intuitive, showing each event on a map and giving data such as categorisation in visual formats.

AFOPSS integrates with PTZ CCTV, security lighting and GIS mapping systems, and will interface with security systems, IT networks, mobile communication and the Internet for remote monitoring and control.



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AFOPSS can simultaneously monitor multiple zones on pipelines of any length.

8.2.3.4 Simple and Rapid Installation

AFOPSS is simple to install and configure, if an existing re8dundant fibre in a SCADA cable is not available, then a new sensing cable can easily be attached to a pipeline or simply buried next to it regardless of ground conditions, using standard telecom methods.

8.2.3.5 High Resilience, Intrinsically Safe and Low Maintenance

Resilient configurations can maintain full protection even if the fibre is cut, giving the precise location of the breach.

The sensor fibre requires no power or additional equipment along its length and is resistant to RF or any other EMI, it is also unaffected by lightning and does not corrode, so once deployed it is essentially maintenance free.

8.2.3.6 AFOPSS Delivery

Westminster can provide full project planning, design, installation, integration and ongoing support worldwide.

The AFOPSS system can also be provided as part of a fully integrated pipeline integrity and security system.

8.2.3.7 AFOPSS - Key Advantages:-

• Simple installation;

• 50 km range one unit, multiple units will cover any length;

• Industry leading sensitivity;

• Accurate location of events down to 1 metre;

• Instantaneous detection of acoustic / vibration events;

• Detection zones easily and remotely reconfigured

• Full integration with security management systems;

• GPS integration with GIS mapping systems;

• Intuitive graphical user interface;

• Multi-platform integration to web, mobile, PC and smart-phones;

• Intelligent characterisation of detected events;

• Sensor is intrinsically safe in explosive environments;

• Undetectable sensor with no EM footprint;

• Immune to RF and all EMI;



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• Interrogator configurable via secure connection;

• Low maintenance and extremely robust sensor.

8.2.3.8 Sensing System Technical Specifications

• Maximum fibre length 50 km;

• Maximum spatial resolution @ 15 km 1 m;

• Maximum spatial resolution @ 50 km ±5 m;

• Minimum separation for discrimination of unique events ± 2 m;

• Maximum signal bandwidth 10 kHz.

Typical Threats

Hot Tapping

Typical Non-Threats

8.2.3.9 Operation

The system has standard event recognition software, when commissioned the system will be set in a learning mode for period of time to experience all of the local environment conditions, those that are non threats will then be assigned as non alerts.

The system acts as a microphonic cable, sound can be 'heard' along the entire sensor fibre length.



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The system sensor interrogator generates a special signal in the optical fibre cable, this signal is changed by sound or ground borne vibrations and the interrogator receives and interprets these vibrations as either a threat or non threat.

Once programmed with the event recognition software, the interrogator can identify and locate the likely cause of the sound / vibrations and automatically send an alarm of a threat.

The alarm threat information is displayed on a user-friendly graphical interface; the system incorporates a "listen-in" mode to enable the user to actually hear what is going on at a particular location.

8.2.3.10 Graphical User Interface

The AFOPSS is supplied with a simple graphical user interface, providing:-

• Full integration with security management systems;

• GPS integration with GIS mapping systems;

• Intuitive graphical user interface;

• Multi-platform integration to web, mobile, PC and smart-phones.

8.2.3.11 PIG Monitoring

Pipe Inspection Gauges (PIG) are used extensively in the pipeline industry to for cleaning, inspection and various maintenance operations on a pipeline. This is normally carried out without stopping the flow of the product in the pipeline.

The PIG can often become stuck in the pipeline during its operation, when this happens the actual location of the PIG in the pipeline is not known.

AFOPPS can provide real time monitoring of the PIG's travel / location along the pipeline.

8.2.3.12 Leak Detection

Detecting leaks caused by defective pipes, illegal tapping, landslide, earthquakes or terrorist activity in surface, buried and underwater pipelines is often a major challenge

AFOPPS will constantly check the integrity of a pipeline preventing environmental damage as well as extending the life of the pipeline by ensuring that it is safe at higher pressures for longer.

A simple communication fibre mounted alongside a pipeline can detect in real time the early stages of a leak such as in-frequent bubbling or low volume leaks before anything more catastrophic damage can occur.

8.2.3.13 Perimeter Intruder Detection

AFOPSS can be used to operate as a perimeter intrusion detection system around pipeline facility buildings i.e. pumping / valve locations using the same fibre sensing cable; this can be integrated with local CCTV systems to provide full security coverage of the local area.



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The AFOPSS can be utilised to provide remote condition monitoring of rotating machinery at in-line facilities i.e. pumping / valve locations using the same fibre sensing cable

8.2.4 Westminster Dual Purpose Pipeline Security and Leak Detection

System

The protection of pipelines against sabotage, illegal tapping and terrorist action combined with the detection of leaks in buried pipelines etc. is a high priority in all countries but until now has been notoriously difficult to achieve. Westminster's unique solution to this problem is to provide a dual purpose Acoustic Fibre Optic Pipeline Security system utilising the same fibre-optic cable throughout the pipeline. This system allows the detection of illegal tapping's or sabotage of the pipeline, whilst also providing the benefit of real-time monitoring against any ruptures or leaks.



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Chapter 9

Conclusion

9.1 Strategies for Exploration

The last decade saw total new global O&G resource additions exceed consumption while yet-to-find estimates were revised significantly upwards.

New resources totaling 800 billion bbl of oil equivalent were added (1.5 times cumulative consumption), while global yet-to-find resources are now estimated to be close to 4 trillion boe, three times more than 10 years ago), underpinned by the addition of unconventional resources but also resources in the Arctic and deep offshore. New ideas, technological developments, and rising prices strongly supported the expansion of the global opportunity set, the combination of which has just started to shape the long term future of the industry.

Deepwater exploration is arguably the most important high-risk high-cost strategy in terms of capital and technology the international industry has developed in recent decades, with a total of 85-90 billion boe discovered in 2000-11 following several country openings and new basin tests.

However as predicted 10 years ago, Brazil, the US Gulf of Mexico, and West Africa remain the big themes with only East Africa added as a new deepwater gas play that could rival the East Mediterranean.1 Many basins have failed to provide either sufficient materiality or even a positive result.

Meanwhile, access to deepwater Brazil by foreign international oil companies has been constrained, the US gulf is still recovering post-Macondo, Mexico is struggling to find a formula to attract investment, Nigeria is no longer an attractive proposition, and domestic Indian players are holding tight to the vast yet marginal deepwater domestic acreage. On the positive side, Angola has just offered its most prospective deepwater acreage.

The 4 decades-long deepwater E&P adventure has created huge value, 7.2 million boe/d of current production, and a large reserve base that is yet to be developed, but in an industrial and geological-strategic sense deepwater exploration has in our view entered its own "end game."

In general, despite oil price decks of $100, all the major types of reserves have become harder to commercialize while the industry seems to be going back to onshore plays. Excluding the Middle East and deepwater opportunities, the most thought-after remaining material options are unconventional, extra heavy oil, and Arctic resources. These may be accessible under equity ownership but are high cost, environmentally sensitive, involve a large technological risk, and have very long lead times. Beyond these, new exploration themes exist but will



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require players to redirect their exploration strategies, become familiar with the many and new types of risks and geographies, and ultimately modify how they execute projects.

9.2 Post-2000

During 2000-11, global exploration resulted in the addition of 380 billion boe of proved and probable conventional reserves.

Some 80-100 billion boe were discovered in post-2000 accessed licenses, the bulk of which are in deep water. The big exploration themes of the last decade include: Former Soviet Union (Caspian), China onshore, Australian offshore, Brazil presalt, Angola deepwater, US gulf deepwater, Middle East onshore, and East Africa/Mozambique deep water. Other new, much discussed discoveries in Ghana, Uganda, India, Israel, Guyana, and now Kenya have been small in both absolute and relative terms and so far appear to offer limited upside.

Looking at the unconventionals or "difficult hydrocarbons" (exploration risk is virtually zero), there was significant testing and proving of resources in Australia (coalbed methane), Canada (bitumen, shale gas), US (shale gas and tight oil), and Venezuela (extra heavy oil).

Although there are no reliable official estimates, consultations with government agencies, industry, published literature, and independent assessments suggest that some 400 billion boe have been delineated, tested, or proved. US shale gas has been among the biggest, estimated at some 100-150 billion boe.

There is no doubt that the increase in industry's access to prospective acreage and discovered reserves was significant, if not a record. And in the last 12 months, new groundbreaking access has taken place in Angola presalt, China shale gas, and more recently in Russia's Arctic, totaling prospective yet-to-find reserves of 380 billion boe (Fig. 1). Yet except for Africa rift basins no new access in less-known, studied onshore basins with large potential conventional oil and gas has taken place.



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In terms of competition, the number of E&P players has increased sharply while many evolved beyond the traditional operator role. In 2000, there were around 500 active E&P players while in 2011 the number was close to 1,000.

Today, the E&P competitive environment includes companies ranging from IOCs, NOCs, large and small E&P independents, private equity, trust funds, sovereign wealth funds, investment banks, local players, utilities, industrial conglomerates, traders, and miners, among others.

In deep water, a highly complex and high-risk operation, more than 90 companies are active compared with 20 just 15 years ago.

Undoubtedly, the most strategically relevant set of new international E&P players that emerged during the last decade via mergers and acquisitions include the Asian NOCs and Statoil, in exploration Petrobras and the independents, and in unconventionals the independents—in fact, as a whole the NOCs and independents dominated the new access game during much of the last decade.

IOCs lagged behind in major discoveries-exploration in new trends (Brazil presalt, Turkmenistan, US shale, East Africa deep water, etc., as well as in smaller plays such as rift basins onshore Africa) even though they have long been the dominant players in bitumen and extra-heavy oil.

The Chinese NOCs have transformed themselves from pure state entities with domestic focus and limited international capacity to globally active E&P players (present in over 30 countries including the US, Canada, and Australia) with assets in all the new major plays (still risk adverse to exploration but with an evolving apetite) backed by their solid balance sheets. In general, NOCs grew faster than many IOCs in term of reserves, production, and balance sheet, and most have remained unchallenged in the top ranks in virtually every metric.

9.3 M&A/Capex shift

Between 2000 and 2011 there were over 13,000 M&A deals worth $1.5 trillion in which more than 100 billion boe of proved reserves, about 50% gas, and 30 million boe/d of production were transacted.

M&A spending became increasingly led by NOCs, characterized by large assets, JVs, and complex corporate deals. Relatively speaking, most deals were in North America, Russia, and Europe, while deals in unconventional resources in North America and Australia became the new theme. In deep water most of the activity took place in Brazil and the US gulf as asset deal flow outside these regions was limited.



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Reflecting the capital intensity of the industry and the significant capital available in NOCs and SWFs, organic E&P Capex (excluding M&A), global Capex (in real terms) increased from just over $100 billion in 2000 to $600 billion in 2012. Cumulative E&P Capex spending totaled $3.5 trillion, exceeding all expectations and forecasts (in 2006 the International Energy Agency projected cumulative upstream investment at $2.3 trillion from 2001 to 2010).

Regionally, Capex in Mexico, Brazil, Russia, and Canada expanded greatly as a total share, while the share of IOC Capex decreased to less than 25%. Offshore Capex, including deep water, rose steadily to represent 40% of the total industry E&P Capex (Fig. 2).

9.4 Deepwater Situation

Global offshore exploration (including deep water) contributed to 170 billion boe or nearly 45% of the total new conventional reserves.

Of this, deep water accounted for 85-90 billion boe of new reserves. As of 2011, estimated global deepwater discovered reserves totaled 160-170 billion boe proved and probable. This compares with 30-40 billion boe in 2000.

Global oil and gas deepwater production stands today at 7.2 million boe/d (circa 5% of global oil and gas), up from virtually nothing in 1990, and remains dominated by the incumbent IOCs, Petrobras, and independents, however with reevaluation of the risks in the wake of the Macondo blowout, this picture is expected to change.



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In terms of water depth, less than 1 million boe/d comes from 1,000 m or less, the rest comes from deeper water; the latest production record is 2,700 m of water. The growth in deep water was strongly underpinned by technological breakthroughs (seismic, drilling, riser, well), new reserves additions, rising prices, and more players involved.

Deepwater oil production is now close to 6.2 million b/d, mostly from Brazil, the US gulf, Angola, and Nigeria. As for deepwater gas, current production is now 1 million boe/d, and the most significant contributors are the US gulf, India, Egypt, Brazil, and Nigeria.

Taking recent official published studies and assessments, deepwater yet-to-find resources could be as high as 500 billion boe. Of this, the Big 4—Brazil, US gulf, Angola, and Nigeria—account for 320 billion boe, while accounting for the rest are 35 other countries, many of which represent small-scale or one-off opportunities; however, it is worth noting that the yet-to-find estimates in the mid-1990s for the Big 4 totaled around 60-100 billion bbl of oil.

9.5 Last Steps

For several decades, industry access to equity reserves and prospective areas has been limited to less than 10% of the global resource base, and a further roughly 10% has been available through NOC and-or direct government access under different contractual terms.

Industry operations evolved from their onshore origins to shallow water operations (1950s), to deep water (1970s onwards), and to increasingly harsh environments such as deserts, rough seas, jungles, and ice-infested waters; offshore Arctic and many exotic Arctic projects have been talked about for decades with limited success.

Few would argue that material opportunities have diminished in conventional onshore and shallow water basins in the 100 countries with such resources. The international industry mainly operates and derives most of its profits from 20 or so countries and profit hubs.

Today, after 40 years of exploration, deep water has also reached this point. The other remaining material opportunities for equity access are characterized by low exploration risk un-conventionals, extra heavy oil, and high exploratory risk Arctic resources (Figs. 3 and 4).



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A not yet very well understood but potentially material new exploration "theme" are the rift basins and unexplored intracratonic sedimentary basins; having said this, in recent years we have seen strong activity in rift basins across Africa with increasing success. In North America, recent developments in horizontal drilling and hydraulic fracturing have highlighted the multibillion barrel oil potential for example of the Late Devonian Bakken shale formation of the Williston basin. Outside of North America, these types of basins may be also found in Brazil, Africa, Eastern Europe, the Bazhenov shale of Western Siberia-Russia, China, and Australia.2 Compared with North America, all of these have few wells in very large areas and much less oil and gas discovered, leaving an open question and perhaps a large opportunity.

However, for any of these types of reserves, particularly the most capital intensive ones, to be monetized, operators will need to manage new aboveground challenges. Beyond just macropolitical and economic stability in the country of operation, companies face increasingly surface issues to secure a license to operate. These include nascent, evolving energy policies and fiscal frameworks, social issues, varying levels of regulatory capacity, increasing environmental liabilities, as well as an array of risks that impact operating conditions, such as local community relations. Particularly for Arctic, deepwater, and unconventional resource development, investors' ability to manage these largely nontechnical, socioeconomic risks will be critical.



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In many jurisdictions, the potential rewards do not outweigh the aboveground risks, meaning that investment and development in many countries are likely to be delayed or dropped (Fig. 5). Especially in many of the frontier deepwater plays in Latin America and in Sub-Saharan Africa, high levels of political instability, regulatory uncertainty, changing fiscal terms, and significant technical barriers to operations will likely delay in some cases the pace of resource development.

In emerging unconventional plays with sprawling surface footprints, land rights issues and local community opposition are likely to be key aboveground risk challenges, while in the Arctic more stringent safety and environmental regulations will make it difficult for all but the most experienced and patient companies to lead development efforts.

The end game is defined by accessing and producing difficult hydrocarbons from a massive opportunity set but at high capital cost, replete with new technical and socioeconomic challenges and a changing set of players at the table. It is an end game in which only the flexible and patient will be winners.

The long arc of evolving technological, economic, and geopolitical factors that have determined exploitation of oil and gas since the mid-19th century has now clearly entered the hydrocarbon resource pyramid's base—the end game is on.

The resource types are few but enormous; their exploitation massively capital intensive with subsurface technical complexity and unprecedented aboveground socioeconomic challenges. While perverse for an end game, the players are many, and many are newcomers to the game, but they all know that few can bear the risks and costs alone. All in, the next exploration frontier appears to be back to unexplored onshore basins, and this is where we are likely to see the next wave of competition and developments take place.



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