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List of Figures

Auxiliary figure index for the web edition. Each entry jumps to the figure caption inside the relevant chapter.

Chapter 1: General Introduction

  1. Figure 1: African Petroleum Development Paradox. Resource wealth does not automatically translate into broad-based economic development.
  2. Figure 2: African Value Capture Gap. Most value generated from hydrocarbon resources is created beyond crude oil production through refining, petrochemicals, manufacturing, and consumer products.
  3. Figure 3: Integrated African Petroleum Industry Model. Transforming hydrocarbon resources into long-term economic growth and sustainable development.

Chapter 2: Emerging Petroleum Provinces in West Africa

  1. Figure 4: Key emerging petroleum provinces across West Africa.

Chapter 5: Hydrocarbon Value Chain

  1. Figure 5: Petroleum Industry Value Chain
  2. Figure 6: Map of the MSGBC Basin
  3. Figure 7: Map showing sedimentary basins within the northern Gulf of Guinea region of West Africa
  4. Figure 8: Map showing the sedimentary basins of Mali and Niger
  5. Figure 9: Products Obtained from Atmospheric Distillation of Crude Oil in a Refinery
  6. Figure 10: Simplified representation of the current petroleum value chain in many African countries, where crude oil is exported and higher-value refined products are subsequently imported.
  7. Figure 11: Integrated African petroleum industry model illustrating how hydrocarbons can support energy security, industrialisation, employment creation, and economic diversification.
  8. Figure 12: Examples of Natural Gas Monetisation Pathways in West Africa
  9. Figure 13: Increasing value capture achieved as hydrocarbons move from upstream production to refining, petrochemicals, and manufacturing activities.
  10. Figure 14: African Petroleum Industrialisation Model: From Hydrocarbon Resources to Economic Development

Chapter 6: Upstream Operations and Government Roles

  1. Figure 15: Petroleum Project Lifecycle - Investment Profile, Revenue Generation and Regulatory Milestones
  2. Figure 16: Typical Petroleum Licensing Process for the Award of Exploration Acreage or Petroleum Blocks
  3. Figure 17: Gravimetric Survey
  4. Figure 18: Aeromagnetic Anomalies and Structural Interpretation of the Benin Coastal Sedimentary Basin. (a) Aeromagnetic anomaly map highlighting subsurface structural trends and fault systems within the basin. (b) Geological and structural interpretation derived
  5. Figure 19: Principle of 3D Seismic Acquisition
  6. Figure 20: Seismic Reflection Section Showing Direct Hydrocarbon Indicators and Exploration Well Placement
  7. Figure 21: Workflow from Seismic Acquisition and Interpretation to Prospect Evaluation and Well Planning.
  8. Figure 22: Integrated Electromagnetic and Seismic Interpretation Showing High-Resistivity Anomalies Associated with Potential Hydrocarbon Traps and Exploration Well Positioning
  9. Figure 23: Geological Cross-Section of the Deer-Boar Petroleum System at the Critical Moment (250 Ma), Illustrating Source Rock Maturation, Hydrocarbon Migration Pathways, Reservoir Development, and the Stratigraphic and Geographic Extent of the Petroleum System
  10. Figure 24: Regional Geological and Petroleum Systems Cross-Section of the Benin Coastal Sedimentary Basin, Illustrating Source Rock Distribution, Hydrocarbon Migration Pathways, Reservoir Intervals, Structural Traps, and Identified Prospects and Discoveries (Modified after Kerr-McGee, 2003)
  11. Figure 25: Seismic Reflection Section Showing a Structural Closure (Anticline) with High-Amplitude Reflectors Indicative of a Potential Hydrocarbon Accumulation.
  12. Figure 26: Common Structural and Stratigraphic Hydrocarbon Trap Types Showing the Principal Geological Configurations that Enable Oil and Gas Accumulation Beneath Effective Seal Rocks.
  13. Figure 27: Two-Way Travel Time (TWT) Structure Map of the Top Reservoir Horizon of a Prospect Showing Structural Closure, Crest Position, Fault Control, and the Hihon-1 Well Location.
  14. Figure 28: Simplified Geological Chance of Success (Pg) Assessment Showing the Three Fundamental Exploration Risk Elements: Source Rock, Reservoir, and Trap.
  15. Figure 29: Example Geological Chance of Success (CoS) Assessment Workflow Showing the Evaluation and Integration of Key Petroleum System Risk Elements.
  16. Figure 30: Example Exploration Prospect Showing the Proposed Exploration Well Location Relative to the Interpreted Structural Closure and Top Reservoir Structure.
  17. Figure 31: Typical Offshore Drilling Units Used During Exploration Activities, Including Drilling Barges, Jack-Up Rigs, Semi-Submersible Rigs, and Drillships, and Their Relative Water Depth Operating Ranges.
  18. Figure 32: Example Wireline Logging Suite Used for Reservoir Evaluation, Illustrating the Integration of Gamma Ray, Resistivity, Density, Neutron, Sonic, and Photoelectric Logs for Lithology, Porosity, Fluid Saturation, and Reservoir Quality Assessment.
  19. Figure 33: Possible Outcomes of Exploration Drilling Operations, Ranging from a Dry Hole to a Hydrocarbon Discovery and Ultimately a Commercial Discovery Suitable for Field Development.
  20. Figure 34: Discovery Well and Subsequent Appraisal Wells Used to Delineate the Extent, Geometry, Reservoir Quality, Fluid Contacts, and Commercial Potential of a Hydrocarbon Accumulation.
  21. Figure 35: Typical Pressure Build-Up Test Showing Pressure Recovery Following Well Shut-In and the Determination of Reservoir Pressure, Permeability, Skin Factor, and Reservoir Boundaries.
  22. Figure 36: Example Static and Dynamic Reservoir Models Used During Field Appraisal to Characterise Reservoir Geometry, Petrophysical Properties, Fluid Distribution, and Forecast Future Reservoir Performance.
  23. Figure 37: Petroleum Resources Management System (PRMS) Classification Framework Showing the Relationship Between Reserves, Contingent Resources, and Prospective Resources According to Project Maturity and Geological Certainty.
  24. Figure 38: Geological Core Storage Facility Used for the Preservation, Cataloguing, and Long-Term Management of Subsurface Data to Support Exploration, Appraisal, and Future Resource Development Activities.
  25. Figure 39: Preserved Drill Core Samples Stored in a Geological Repository, Providing Direct Evidence of Lithology, Sedimentary Structures, Reservoir Quality, and Hydrocarbon Occurrence for Exploration and Development Studies.
  26. Figure 40: Examples of Development Concepts for Oil & Gas Developments
  27. Figure 41: Reservoir Evaluation and Field Development Planning Workflow.
  28. Figure 42: Example of a Three-Dimensional Reservoir Model Used for Field Development Planning.
  29. Figure 43: Typical Hydrocarbon Production and Processing Facilities.
  30. Figure 44: Government Approval Process for a Field Development Plan. Typical sequence of regulatory reviews, consultations, and approvals required before a hydrocarbon field development can proceed to implementation and production.
  31. Figure 45: Common well types used to produce, inject, and monitor fluids within a hydrocarbon reservoir.
  32. Figure 46: Comparison of common well configurations used in hydrocarbon developments, illustrating how increased reservoir contact can improve production performance and hydrocarbon recovery.
  33. Figure 47: Examples of offshore production completion systems used to safely control, produce, and transport hydrocarbons from subsea reservoirs to surface processing facilities.
  34. Figure 48: Illustration of a typical deepwater subsea production system showing subsea trees, manifolds, flowlines, umbilicals, and risers used to transport hydrocarbons from the reservoir to offshore production facilities.
  35. Figure 49: A typical FPSO facility showing the key systems used to receive, process, store, and offload hydrocarbons produced from offshore subsea fields.
  36. Figure 50: Typical sequence of activities and decision gates required to progress a hydrocarbon development project from FID through engineering, procurement, construction, commissioning, and start-up to first production.
  37. Figure 51: Illustration of the integrated production system used to extract, process, transport, and export hydrocarbons from the reservoir to domestic and international markets.
  38. Figure 52: Typical workflow used to acquire, analyse, and interpret reservoir and production data to monitor performance, optimise recovery, and support field management decisions throughout the life of a hydrocarbon field.
  39. Figure 53: Examples of the principal artificial lift systems used to enhance hydrocarbon production when natural reservoir energy is insufficient to sustain economic flow rates.
  40. Figure 54: Illustration of the principal hydrocarbon recovery mechanisms, showing how primary, secondary, and tertiary recovery methods are applied to increase reservoir recovery and maximise ultimate hydrocarbon production.
  41. Figure 55: Typical hydrocarbon production profile illustrating the progression from start-up and production ramp-up through plateau production and eventual field decline as reservoir energy is depleted.
  42. Figure 56: Illustration of a typical asset integrity management framework showing the processes, controls, and continuous improvement activities used to ensure the safe, reliable, and efficient operation of petroleum facilities throughout their lifecycle.
  43. Figure 57: Illustration of the typical petroleum field lifecycle, from exploration and appraisal through development and production to decommissioning, abandonment, and site restoration at the end of field life.
  44. Figure 58: Typical sequence of activities undertaken during petroleum asset decommissioning, including planning, facility removal, well abandonment, site clearance, and environmental restoration.
  45. Figure 59: Typical well plugging and abandonment configuration showing barrier placement and the removal of wellheads, conductors, and surface facilities.
  46. Figure 60: Examples of offshore facilities and subsea infrastructure that may require decommissioning at the end of field life, including platforms, FPSOs, subsea systems, pipelines, umbilicals, and associated support assets.
  47. Figure 61: Key environmental considerations during petroleum decommissioning, including habitat protection, waste management, emissions control, seabed disturbance, and site restoration.
  48. Figure 62: Examples of the principal engineering challenges encountered during offshore decommissioning, including structural integrity, heavy lifting, subsea intervention, environmental constraints, logistics, and cost management.
  49. Figure 63: Typical regulatory process for the review, assessment, and approval of petroleum decommissioning plans prior to the commencement of decommissioning activities.
  50. Figure 64: Typical onshore site restoration activities undertaken following petroleum operations, including facility removal, remediation, land recontouring, revegetation, and long-term environmental monitoring.
  51. Figure 65: Typical offshore site restoration activities undertaken following petroleum operations, including infrastructure removal, seabed clearance, environmental remediation, habitat recovery, and long-term monitoring
  52. Figure 66: Typical framework used to monitor, verify, and demonstrate the long-term environmental and regulatory performance of decommissioned petroleum facilities and sites.
  53. Figure 67: Typical cash flow profile of an upstream petroleum project from licensing and exploration through production and eventual abandonment.

Chapter 8: Petroleum Fiscal Regimes

  1. Figure 68: The economic value of hydrocarbon resources is primarily determined by recoverability, market conditions, and the fiscal regime governing petroleum exploration, development, and production activities.
  2. Figure 69: Illustration of how production revenues are allocated between cost recovery, contractor entitlement, and government take under a typical petroleum fiscal regime.
  3. Figure 70: Overview of the principal petroleum fiscal regimes used worldwide, including concessionary systems, service contracts, and production sharing contracts, together with examples of countries where they are applied.

Chapter 9: West African Fiscal Regimes

  1. Figure 71: Comparison of cost recovery limits under selected West African petroleum fiscal regimes, illustrating variations by country and development environment.
  2. Figure 72: Simplified Illustration of State and Contractor Revenue Sharing under Fiscal Regime in Benin.
  3. Figure 73: Simplified Illustration of State and Contractor Revenue Sharing under Fiscal Regime in Ghana.
  4. Figure 74: Simplified Illustration of State and Contractor Revenue Sharing under Fiscal Regime in Côte d’Ivoire.
  5. Figure 75: Simplified Illustration of State and Contractor Revenue Sharing under Fiscal Regime in Nigeria.
  6. Figure 76: Simplified Illustration of State and Contractor Revenue Sharing under Fiscal Regime in Senegal.
  7. Figure 77: Simplified Illustration of State and Contractor Revenue Sharing under Fiscal Regime in Niger.
  8. Figure 78: Distribution of Net Profit Between the Contractor and the State Under Selected West African Petroleum Fiscal Regimes.
  9. Figure 79: Distribution of Cash Flow Between the Contractor and the State for Every 100 Barrels of Oil Produced.

Chapter 12: Vision for West Africa 2050

  1. Figure 80: African Petroleum Industrialisation Model: From Hydrocarbon Resources to Economic Development