competent persons report for camac energy inc v1

CAMAC Energy Inc. Copy No. EL-12-219600

COMPETENT PERSON’S REPORT ON CERTAIN PETROLEUM ASSETS

NIGERIA, GAMBIA AND KENYA

Prepared for

CAMAC ENERGY INC.

DECEMBER, 2013

www.gaffney-cline.com

CAMAC EL-12-219600

Page No. INTRODUCTION ................................................................................................... 1 EXECUTIVE SUMMARY ....................................................................................... 5 DISCUSSION ....................................................................................................... 12 1. BACKGROUND TO BLOCKS OML 120 AND 121, NIGERIA ..................... 12 2. GEOLOGICAL SETTING ............................................................................ 14 3. EXPLORATION HISTORY AND GEOPHYSICAL DATABASE:

OML 120 AND 121 ..................................................................................... 17 4. OYO FIELD ................................................................................................ 19 4.1 History and Introduction .................................................................. 19 4.2 Geology .......................................................................................... 20 4.3 Geophysics ..................................................................................... 22 4.4 Reservoir Geology .......................................................................... 24 4.5 Field Development, Cost and Schedule .......................................... 26 4.5.1 Overview .............................................................................. 26 4.5.2 Capital and Operating Costs, Development Schedule .......... 27 4.5.3 Development of Adjacent Discoveries .................................. 27 4.6 Technical Assessment .................................................................... 28 4.6.1 FPSO and Marine ................................................................ 28 4.6.2 Wells and Drilling ................................................................. 28 4.6.3 Subsea Architecture ............................................................. 29 4.7 Development Uncertainties ............................................................. 30 4.8 Safety and Environmental ............................................................... 30 4.9 Oyo Central ..................................................................................... 30 4.9.1 Oil in Place........................................................................... 30 4.9.2 Reserves Estimation ............................................................ 31 4.9.3 Proved Reserves (1P) .......................................................... 31 4.9.4 Proved plus Probable (2P) ................................................... 34 4.9.5 Proved plus Probable plus Possible (3P) ............................. 35 4.10 Oyo West Field ............................................................................... 36 4.10.1 Oil in Place........................................................................... 36 4.10.2 Proved Reserves (1P) .......................................................... 37 4.10.3 Proved plus Probable (2P) ................................................... 38 4.10.4 Proved plus Probable plus Possible (3P) ............................. 39 4.11 Contingent Resources .................................................................... 39 4.12 Prospective Resources – Deep Pool Potential at Oyo Field ............ 39

4.12.1 T1B Formation ..................................................................... 39


Page No. 4.12.2 Upper Miocene .................................................................... 40 4.12.3 Other Potential ..................................................................... 42 5. OTHER DISCOVERIES .............................................................................. 43 5.1 Ebolibo-1 ........................................................................................ 43 6. PROSPECTIVE RESOURCES OML 120 AND 121 .................................... 46 6.1 Western OML 120 Miocene Prospects (Oil and Gas) ...................... 50 6.1.1 Prospect G ........................................................................... 50 6.1.2 Prospect Ereng .................................................................... 54 6.1.3 Prospect Ewo North Upthrown (UT) ..................................... 57 6.1.4 Prospect Ewo North Downthrown (DT) ................................ 60 6.1.5 Prospect Q ........................................................................... 64 6.2 Western OML 120 and 121: Pliocene Prospects (Oil and Gas) ....... 67 6.2.1 Prospect O ........................................................................... 67 6.2.2 Prospect P ........................................................................... 69 6.3 Eastern OML 121: Pliocene to Pleistocene Prospects (Gas) ........... 73 6.3.1 Prospect Kigbo .................................................................... 73 6.4 OML 120: Miocene Leads (Oil and Gas) ......................................... 76 6.4.1 Ereng B ................................................................................ 76 6.4.2 Ewo Deep ............................................................................ 76 6.4.3 Lead A ................................................................................. 80 6.4.4 Lead C ................................................................................. 82

6.4.5 Lead D ................................................................................. 84 6.5 Eastern OML 121: Pliocene to Pleistocene Leads (Gas) ................. 86 6.5.1 Lead R ................................................................................. 86 6.5.2 Onigu Lead .......................................................................... 88 6.5.3 Eba Lead ............................................................................. 90 6.5.4 Songu Lead ......................................................................... 92 6.5.5 Lead M ................................................................................. 94 6.6 OML 120: Miocene Leads ............................................................... 96 6.6.1 Kigbo Deep Lead ................................................................. 96 7. GAMBIA ..................................................................................................... 98 7.1 Background ..................................................................................... 98 7.2 Geological Setting ........................................................................... 98 7.3 Exploration History .......................................................................... 100


Page No. 7.4 Prospective Resources ................................................................... 101 7.4.1 West Lead............................................................................ 101 7.4.2 East Lead ............................................................................ 103 8. KENYA ............................................................................................ 104 8.1 Background ..................................................................................... 104 8.2 Geological Setting ........................................................................... 107 8.3 Exploration History .......................................................................... 108 8.3.1 Block L1B ............................................................................ 108 8.3.2 Block L16 ............................................................................. 108 8.3.3 Blocks L27 and L28 ............................................................. 108 8.4 Prospective Resources ................................................................... 109 8.4.1 Block L1B ............................................................................ 109 8.4.2 Block L16 ............................................................................. 110 8.4.3 Blocks L27 and L28 ............................................................. 110 9. ECONOMICS ............................................................................................. 111 9.1 Fiscal Terms ................................................................................... 111 9.2 Price and Inflation Assumptions ...................................................... 113 9.3 Results of Economic Evaluation ...................................................... 113 10. QUALIFICATIONS ...................................................................................... 114 11. BASIS OF OPINION ................................................................................... 114 Tables 0.1 CAMAC Licence Summary ......................................................................... 5 0.2 Summary of Gross and Net Hydrocarbon Reserves

as at 30th June, 2013 .................................................................................. 6 0.3 Summary of Gross and Net Gas Contingent Resources

as at 30th June, 2013 .................................................................................. 7 0.4 Summary of Gross Unrisked Prospective Resources (Prospects)

Nigeria as at 30th June, 2013 ...................................................................... 8 0.5 Summary of Net Company Unrisked Prospective Resources

(Prospects) Nigeria as at 30th June, 2013 ................................................... 9 0.6 Summary of Unrisked Prospective Resources (Leads) Nigeria

as at 30th June, 2013 .................................................................................. 10 0.7 Summary of Unrisked Prospective Resources (Leads) Gambia

as at 30th June, 2013 .................................................................................. 11 3.1 Previous Exploration Wells ......................................................................... 18 4.1 Hydrocarbons Initially in Place Oyo Central Field ....................................... 31 4.2 DCA Parameters per Well for the 3P Case ................................................. 35 4.3 Hydrocarbons Initially in Place Oyo West Field ........................................... 36


Page No.

4.4 Summary of Prospective Oil and Gas in Place Volumes Oyo T1B .............. 40 4.5 Summary of Prospective Oil and Gas in Place Volumes Oyo Deep ............ 42 5.1 Summary of Contingent Oil and Gas in Place Volumes Ebolibo.................. 44 5.2 Summary of Gross and Net Gas Contingent Resources Ebolibo

as at 30th June, 2013 .................................................................................. 44 6.1 Summary of Gross Unrisked Prospective Resources (Prospects)

Nigeria as at 30th June, 2013 ...................................................................... 47 6.2 Summary of Net Company Unrisked Prospective Resources (Prospects)

Nigeria as at 30th June, 2013 ...................................................................... 48 6.3 Summary of Prospective Oil and Gas in Place Volumes Prospect G .......... 54 6.4 Summary of Prospective Oil and Gas in Place Volumes

Prospect Ereng ........................................................................................... 57 6.5 Summary of Prospective Oil and Gas in Place Volumes

Prospect Ewo North UT .............................................................................. 60 6.6 Summary of Prospective Oil and Gas in Place Volumes

Prospect Ewo North DT .............................................................................. 63 6.7 Summary of Prospective Oil and Gas in Place Volumes Prospect Q .......... 65 6.8 Summary of Prospective Oil and Gas in Place Volumes Prospect O .......... 68 6.9 Summary of Prospective Oil and Gas in Place Volumes Prospect P ........... 73 6.10 Summary of Prospective Oil and Gas in Place Volumes

Prospect Kigbo ........................................................................................... 76 6.11 Summary of Unrisked Prospective Resources (Leads) Nigeria

as at 30th June, 2013 .................................................................................. 77 7.1 Exploration Wells Gambia........................................................................... 101 7.2 Summary of Unrisked Prospective Resources (Leads) Gambia

as at 30th June 2013 ................................................................................... 103 8.1 Work Commitments Onshore Blocks L1B and L16, Kenya ......................... 106 8.2 Work Commitments Offshore Blocks L27 and L28, Kenya .......................... 106 8.3 Exploration Wells Blocks L1B and L1A, Kenya ........................................... 108 8.4 Exploration Wells Blocks L06, L10A, L08 and L19, Kenya .......................... 108 9.1 GCA Brent Price Scenario Effective Q3 2013 ............................................. 113 9.2 Summary of Oyo Field Reserves Estimate as of 30th June, 2013 ................ 113 Figures 0.1 Location Map for CAMAC African Assets .................................................... 2 1.1 Location Map for CAMAC Nigerian Assets ................................................. 13 2.1 Chronostratigraphic Diagram for the Northwest Offshore Niger Delta ......... 15 3.1 Seismic Data Coverage and Exploration Wells OML 120 and 121 .............. 17 4.1 Oyo Central Contoured Depth Structure Map Top T1A Reservoir ............... 21 4.2 Oyo West Contoured Depth Structure Top Unit 4 Reservoir

and RMS Amplitudes Representing Unit 3/4 Reservoir Unit ........................ 22 4.3 Vertical Seismic Section through Oyo Central Field with

Contoured Depth Map ................................................................................ 23 4.4 Vertical Seismic Section through Oyo West Field with

Contoured Depth Structure Map ................................................................. 24 4.5 Oyo Central RMS Amplitudes Interval from 30 msec above to 80 msec

below Top T1A Reservoir and Depth Structure Contours at Top T1A Reservoir .................................................................................. 26

4.6 Oyo Field Schematic of Sub-Sea Layout .................................................... 29


Page No. 4.7 Oyo No. 5A ST Performance and 1P Forecast ........................................... 32 4.8 Oyo-5 Flowing Bottom-Hole Pressure ......................................................... 33 4.9 Location of Oyo Well Nos. 7, 8 and 9 .......................................................... 34 4.10 Performance Comparison for 1P, 2P and 3P .............................................. 36 4.11 Oyo No. 6 Historical Performance ............................................................... 37 4.12 1P Forecast for Oyo-6 ................................................................................ 38 4.13 Oyo Central Depth Structure Top Oyo Miocene Reservoir and

RMS Amplitudes (Far Stack Only) for Interval 50 msec Below .................... 41 4.14 RMS Amplitudes for Unit 3/4 at Oyo West Extrapolated into Oyo

Central Area, superimposed on Depth Structure Top T1A Reservoir .......... 42 5.1 Vertical Seismic Section through Ebolibo Discovery with

Depth Contoured Maximum Amplitude Map on A098 Pleistocene Horizon . 45 6.1 CAMAC Prospect and Lead Portfolio OML 120 and 121 ............................. 46 6.2 Vertical Seismic Section through Prospect G with

Depth Contoured Maximum Amplitude Map ............................................... 51 6.3 Stratigraphic Section applied to Prospect G Petrel Model ........................... 52 6.4 3D View to West of Prospect G Petrel Model .............................................. 53 6.5 Vertical Seismic Section (NNW-SSE) through Ereng A Prospect and

Ereng B Lead.............................................................................................. 55 6.6 Vertical Seismic Section (ENE-WSW) through Ereng A Prospect and

Ereng B Lead.............................................................................................. 55 6.7 Contoured Depth Structure Top Ereng A Sand and RMS Amplitudes

for Ereng A Interval ..................................................................................... 56 6.8 Vertical Seismic Section through Ewo North Upthrown (UT) ....................... 57 6.9 Contoured Depth Structure Top Ewo North UT Horizon 1 and

RMS Amplitudes for Horizon 1 Interval ....................................................... 58 6.10 Contoured Depth Structure Top Ewo North UT Horizon 2 and

RMS Amplitudes for Horizon 2 Interval ....................................................... 59 6.11 Vertical Seismic Section through Ewo North Downthrown (DT) Prospect ... 61 6.12 Contoured Depth Structure Top Ewo North DT Horizon 235 and

RMS Amplitudes for Horizon 235 to 245 Interval ........................................ 62 6.13 Contoured Depth Structure Top Ewo North DT Mid Sandstone Horizon 1

and RMS Amplitudes for Mid Sandstone to Lower Sandstone Interval........ 63 6.14 Vertical Seismic Section through Prospect Q with Contoured

Depth Map on Shallow Horizon .................................................................. 66 6.15 Vertical Seismic Section through Prospect O .............................................. 67 6.16 Contoured Depth Structure Top O Prospect Reservoir and RMS

Amplitudes for Interval below H50 Regional Marker including Oyo Canyon Trend ...................................................................... 68

6.17 Vertical Seismic Section through Prospect P .............................................. 69 6.18 RMS Amplitudes for Broad Interval 0.4 secs below H50 Upper

Pliocene Regional Marker ........................................................................... 70 6.19 Contoured Depth Structure Top P Prospect Reservoir and RMS

Amplitudes for Bulk Interval between Top and Base Reservoir ................... 71 6.20 Vertical Seismic Section (Arbitrary Line) through Prospect P ...................... 72 6.21 Contoured Time Structure Map and RMS Amplitudes for Interval

0.075 sec below Top of P Prospect Reservoir ............................................ 72 6.22 Vertical Seismic Section through Kigbo with Depth Contoured

Maximum Amplitude of H114 ...................................................................... 74 6.23 Contoured Maximum Amplitude Maps – Kigbo H114 and H114A ............... 75 6.24 Vertical Seismic Sections through Ewo Deep Lead..................................... 78


Page No. 6.25 Contoured Depth Structure Top Ewo Deep Horizon 1 and RMS

Amplitudes for Bulk Interval between Horizon 1 and 1A .............................. 79 6.26 Vertical Seismic Section through Lead A with Contoured Time Map

on Top Miocene Horizon ............................................................................. 81 6.27 Vertical Seismic Section through Lead C with Contoured Time Map

on Top Miocene Horizon ............................................................................. 83 6.28 Vertical Seismic Section through Lead D with Contoured Time Map

on Top Miocene Horizon ............................................................................. 85 6.29 Vertical Seismic Section through Lead R with Time Contoured

Maximum Amplitude Map at H110 .............................................................. 87 6.30 Vertical Seismic Section through Onigu with Time Contoured

Maximum Amplitude Extraction from H114 ................................................ 89 6.31 Vertical Seismic Section through Eba with Contoured Time Map ................ 91 6.32 Vertical Seismic Section through Songu with Contoured Time Map ............ 93 6.33 Vertical Seismic Section through Lead M with Time Contoured

Maximum Amplitude Extraction at Top M Channel Horizon ........................ 95 6.34 Vertical Seismic Section through Kigbo Deep Lead with

Contoured Time Map .................................................................................. 97 7.1 Location of CAMAC Blocks, Gambia .......................................................... 99 7.2 Stratigraphic Summary, Offshore Gambia .................................................. 100 7.3 CAMAC Lead Portfolio, Gambia ................................................................. 102 8.1 Location of CAMAC Blocks, Kenya ............................................................. 105 8.2 Stratigraphic Summary, Lamu Embayment Basin ....................................... 107 Appendices I. Abbreviated form of SPE PRMS II. Glossary

Gaffney, Cline & Associates Limited Bentley Hall, Blacknest Alton, Hampshire GU34 4PU, UK Telephone: +44 (0)120 525366 Registered Number: 1122740 www.gaffney-cline.com

Registered in England, number 1122740, at the above address

CAR/cxd/EL-12-219600/0254 5th December, 2013 The Directors, CAMAC Energy Inc., 1330 Post Oak Blvd., Suite 2250, Houston, Texas, 77056, U.S.A. Dear Sirs,

COMPETENT PERSON’S REPORT ON CERTAIN PETROLEUM ASSETS FOR CAMAC ENERGY

INTRODUCTION In accordance with the instruction letter of CAMAC Energy Inc. (“CAMAC” or “the Company”), dated 26th February, 2013 Gaffney, Cline & Associates Ltd ("GCA") has assessed the petroleum interests owned by CAMAC offshore Nigeria, Kenya, Gambia and onshore Kenya (Figure 0.1). These assets include the producing Oyo field offshore Nigeria, further discoveries and exploration prospects and leads. The Effective Date of the evaluation is 30th June, 2013. The contents of this report are limited to the acreage operated by CAMAC. CAMAC is currently listed on the New York Stock Exchange. GCA understands that CAMAC intends to publish this Competent Person’s Report (“CPR”), which has been prepared at the request of the Company for the purpose of obtaining a secondary listing on the Johannesburg Stock Exchange. .

GCA accepts responsibility for the CPR insofar as it is based on data provided by CAMAC, which GCA has relied on the accuracy and completeness thereof, and confirms that, to the best of its knowledge and belief having taken all reasonable care to ensure that such is the case, the information contained in the CPR is in accordance with the facts and contains no omission likely to affect its import.

http://www.gaffney-cline.com/

EL-12-219600 CAMAC Energy Inc.

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GCA is an independent energy consultancy specialising in petroleum asset evaluation and economic analysis. In the preparation of this report, GCA has maintained, and continues to maintain, a strict consultant-client relationship with CAMAC. The management and staff of GCA have been, and continue to be, independent of CAMAC in the services they provide to the company including the provision of the opinion expressed in this assessment. Furthermore, the management and staff of GCA have no interest in any assets or share capital of CAMAC or in the promotion of the company.

FIGURE 0.1

LOCATION MAP FOR CAMAC AFRICAN ASSETS

0 500 1000 km

Nigeria

Kenya

Gambia


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CAMAC has made available to GCA a data set of technical information including geological, geophysical, petrophysical and engineering data, analyses and reports, together with financial data and other information pertaining to the fiscal and contractual terms applicable to the assets. In carrying out this assessment GCA has relied on the accuracy and completeness of this information.

The Resources reported herein are in accordance with the definitions of the Society of Petroleum Engineers/World Petroleum Council/American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) Petroleum Resources Management System document (“SPE PRMS”), approved in March 2007 (see Appendix I for an abbreviated version). GCA understands that the SPE PRMS is an acceptable standard for reporting on the Johannesburg Stock Exchange.

Reserves are those quantities of petroleum that are anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized as Proved (1P), Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of Reserve volumes quoted herein have been determined within the context of an economic limit test (pre-tax and exclusive of accumulated depreciation amounts) assessment prior to any Net Present Value analysis. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no evident viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized as 1C, 2C and 3C in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Contingent Resource volumes are presented as unrisked. The stated 'Chance of Development', a percentage which pertains to the probability of achieving the status of a Reserve has not been applied to the volumes presented. Prospective Resources are those quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further categorized as Low, Best and High estimates in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.

Prospective Resources include Prospects and Leads. Prospects are features that have been sufficiently well defined, on the basis of geological and geophysical data, to the point that they are considered drillable. Leads, on the other hand, are not sufficiently well defined to be drillable, and need further work and/or data. In general, Leads are significantly more risky than Prospects and therefore are not suitable for explicit quantification.


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Prospective Resource volumes are presented as unrisked. The stated 'Geological Chance of Success' (GCoS), a percentage which pertains to the probability of achieving the status of a Contingent Resource (where the Geological Chance of Success is unity) has not been applied to the volumes presented. This dimension of risk assessment does not incorporate the considerations of economic uncertainty and commerciality.

The reported hydrocarbon volumes are estimates, based on professional judgment and are subject to future revisions, upward or downward, as a result of future operations or as additional information becomes available.

Oil volumes appearing in this report have been quoted at stock tank conditions. Typically these volumes have been referred to in million barrel increments (MMBbl). Natural gas volumes have been quoted in billions of standard cubic feet (Bscf) and are volumes of sales gas. Standard conditions are defined as 14.73 psia and 60° Fahrenheit. Appendix II is a glossary of oilfield terms, some or all of which may be used in this report.

GCA has not undertaken a site visit of the assets. As such, GCA is not in a position to comment on the operations or facilities in place, their appropriateness and condition and whether they are in compliance with the regulations pertaining to such operations. Further, GCA is not in a position to comment on any aspect of health, safety or environment of such operation. GCA confirms that, to the best of its knowledge, there has been no material change of circumstances than stated herein. This assessment has been conducted within the context of GCA’s understanding of the effects of petroleum legislation, taxation, and other regulations that currently apply to these properties and GCA’s best professional judgement, subject to the generally recognised uncertainties associated with the interpretation of geoscience and engineering data. This report has been prepared for CAMAC under the scope of work and terms and conditions agreed in the GCA proposal for services and should not be used for purposes other than those for which it is intended. Any third party receiving a copy of this report is similarly bound by the terms and conditions imposed on CAMAC.


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EXECUTIVE SUMMARY

CAMAC has exploration and production interests in assets offshore Nigeria, offshore Gambia and offshore and onshore Kenya, as listed in Table 0.1.

TABLE 0.1

CAMAC LICENCE SUMMARY

Country Licence Working Interest

(%) Operator Partner Area

(km2)

Gambia A2 100 CAMAC Energy GNPC 1,294.10 A5 100 CAMAC Energy GNPC 1,387.70

Kenya

L1B 100 CAMAC Energy Ministry of Energy, Kenya 12,407.20 L16 100 CAMAC Energy Ministry of Energy, Kenya 3,644.00 L27 100 CAMAC Energy Ministry of Energy, Kenya 10,600.00 L28 100 CAMAC Energy Ministry of Energy, Kenya 10,430.00

Nigeria OML 120 30 CAMAC Energy Allied Energy PLC 930.00 OML 121 30 CAMAC Energy Allied Energy PLC 877.90

The Nigerian license is governed by the Nigerian Deep Offshore & Inland Basin Production Sharing Contract (PSC) Act 1999 Terms. The Oil Mining Lease (OML) provides for a 12% royalty payment along with a Petroleum Profit Tax (50% of the Chargeable profit) and an Education Tax (2% of Assessable profit), and NDDC tax (3% of capital budget) all of which is paid to the government. GCA also understands that there is a commercial production sharing agreement between CAMAC and its partner Allied Energy Resources for OML 120 and 121. The summary of the carry as understood by GCA and reflected in the net entitlement and NPV calculation is as follows: • CAMAC pays no CAPEX and OPEX in 2013 but thereafter it pays its equity share

of all costs; • Cost oil limit is 80% net of royalties; • Cost oil split is 70% Allied and 30% CAMAC; and • Profit oil split is 49% Allied and 51% CAMAC. Both the Gambia and Kenya acreage are held under Production Sharing Contracts with the host governments. The single producing asset is the Oyo Field in OML 120, offshore Nigeria, which consists of two oil and gas pools, Oyo Central and Oyo West, in Pliocene sandstones at approximately 1,700 m depth in 300 m water. GCA has evaluated the single producing wells in each of the two pools (Oyo-5 in Oyo Central and Oyo-6 in Oyo West) and the proposed further development drilling (Oyo-7 to Oyo-12), taking into account likely well performance and reservoir variation to produce an estimate of hydrocarbon reserves (Table 0.2).


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TABLE 0.2

SUMMARY OF GROSS AND NET HYDROCARBON RESERVES AS AT 30th JUNE, 2013

Category Gross Oil (MMBbl)

CAMAC Net Entitlement Oil (MMBbl)

Total Proved (1P) 10.85 2.8 Proved + Probable (2P) 14.05 3.7 Proved + Probable + Possible (3P) 32.10 7.9 Note: 1. Net entitlement reflects the terms of the agreement between CAMAC and Allied based on a cost oil

+ profit oil basis as described above and also reflects CAMAC’s additional carried interest in past investments.

Recovery Factors GCA has reviewed the recovery factors suggested by CAMAC and given the current understanding of the Oyo field, GCA considers that in general the suggested ranges of recovery factors are appropriate. However, for prospective accumulations predicted to contain only oil phase hydrocarbons, GCA has revised CAMAC’s estimations. Where a lead or prospect has a predicted mixed phase hydrocarbon (oil and gas) content, GCA has used a range in recovery factor of 20 to 35%, with a most likely estimate of 30% for oil. A range of 50 to 70% with a most likely estimate of 60% is used for gas phase hydrocarbons in a mixed phase reservoir. Where a prospective accumulation has been assessed to contain only oil phase hydrocarbons, a range in recovery factor of 25 to 45% has been used, with a most likely estimate of 35%. Where a prospective accumulation has been assessed to contain only gas phase hydrocarbons, a range in recovery factor of 50 to 70% has been used, with a most likely estimate of 60%. These recovery factors have been incorporated into the Monte Carlo simulations with triangular distribution functions. Oyo Contingent Resources post ELT The Oyo field reservoir is technically capable of producing oil volumes beyond the economic limit of the field for the 1P and 2P cases outlined above. GCA has estimated the volumes of oil that could be produced from Oyo wells -6 through -9 up to 2026; which would require a 5 year extension to the existing licence, the Petrojarl FPSO to remain operationally viable (it would be 40 years old in 2026). No economic limit is applied to these Contingent Resource volumes, hence only Gross Volumes are documented as CAMAC’s net entitlement volumes can only be estimated when profit oil split is known. In addition, OML 121, offshore Nigeria, contains contingent gas resources at one discovery in Pleistocene sandstones at Ebolibo-1, summarized in Table 0.3. In preparing these estimates for Ebolibo, GCA has used a probabilistic methodology, both to assess the range of in-place volumes and recoverable contingent resources.


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TABLE 0.3

SUMMARY OF GROSS AND NET GAS CONTINGENT RESOURCES AS AT 30th JUNE, 2013

Asset Name

Licence Name

Gross Contingent Resources

(Bscf) Working Interest

(%)

Net Contingent Resources (Bscf)

1C 2C 3C Mean 1C 2C 3C Mean

Oyo OML 120 4.47 4.21 0 n/a 30

Not measurable, no profit split beyond ELT.

n/a

Ebolibo OML 121 71 120 188 126 30 21 36 57 38

Notes: 1. The meaningful Contingent Resource volume reported here is the Gross 2C, or ‘Best Estimate’

value. 2. No economic limit cut off is applied for Contingent Resources. 3. It is not feasible to compute CAMAC’s Net Contingent Resource volume in Oyo beyond the

economic limit as it is partly dependent on profit split, which by definition is zero, i.e. no profits beyond ELT.

4. The volumes reported here are “Unrisked” in the sense that “Chance of Development” values have not been arithmetically applied to the designated volumes within this assessment. “Chance of Development” represents an indicative estimate of the probability that the Contingent Resource will be developed, which would warrant the reclassification of that volume as a Reserve.

Blocks OML 120 and 121, offshore Nigeria, have prospective resources of oil and gas in 10 prospects and 12 leads. Hydrocarbon shows in previous wells (Oyo-1) on the Oyo field indicate deeper pool potential in Lower Pliocene and Miocene sandstones, which are included in the summary of prospective resources. These sandstones of Miocene and Pliocene age at depths ranging from 1,500 m to 3,700 m ss and include prospective resources of both gas and oil. Water depths range from 200 m to 850 m. Prospective Resources for OML 120 and 121 are presented in Tables 0.4 and 0.5 (Prospects) and 0.6 (Leads)


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TABLE 0.4

SUMMARY OF GROSS UNRISKED PROSPECTIVE RESOURCES (PROSPECTS) NIGERIA AS AT 30th JUNE, 2013

Prospect Name

Licence Name

Gross Unrisked Prospective Resources GCoS

(%) (MMBbl) (Bscf) Low Best High Mean Low Best High Mean

P OML 121 11 41 96 48 191 427 805 470 56 G OML 120 39 64 181 118 17 24 33 24 56 Oyo T1B OML 120 1 2 4 2 1 3 7 3 64 Oyo Deep OML 120 0 1 3 2 0 1 3 1 35 Ereng OML 120 42 78 134 85 27 90 196 103 13 Ewo North UT OML 120 3 17 104 46 4 29 204 92 22 Ewo North DT OML 120 1 3 10 4 12 42 99 51 32 O OML 120 1 2 5 3 30 64 112 68 63 Kigbo OML 121 0 0 0 0 90 226 424 245 42 Q OML 120 54 96 156 102 31 86 175 97 17

Notes: 1. Prospects are features that have been sufficiently well defined, on the basis of geological and

geophysical data, to the point that they are considered viable drilling targets. 2. “Gross Unrisked Prospective Resources” are 100% of the volumes estimated to be recoverable from

the field. 3. The GCoS reported here represents an indicative estimate of the probability that drilling this

Prospect would result in a discovery, which would warrant the re-classification of that volume as a Contingent Resource. The GCoS value for Contingent Resource is, by definition, unity. These GCoS values have not been arithmetically applied to the designated volumes within this assessment. Thus the volumes are “Unrisked”.

4. It is inappropriate to aggregate Prospective Resources without due consideration of the different levels of risk associated with each Prospect/Lead and the potential dependencies between them. Similarly, it is inappropriate to aggregate Prospective Resources with Reserves or Contingent Resources.


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TABLE 0.5

SUMMARY OF NET COMPANY UNRISKED PROSPECTIVE RESOURCES (PROSPECTS) NIGERIA AS AT 30th JUNE, 2013

Prospect Name

Licence Name

Working Interest

(%)

Net Unrisked Prospective Resources GCoS


P OML 121 30 3 12 29 14 57 128 241 141 56

G OML 120 30 12 19 54 36 5 7 10 7 56

Oyo T1B OML 121 30 0 1 1 1 0 1 2 1 64

Oyo Deep OML 120 30 0 0 1 0 0 0 1 0 35

Ereng OML 120 30 13 23 40 25 8 27 59 31 13

Ewo North UT

OML 120 30 1 5 31 14 1 9 61 28 22

Ewo North DT

OML 120 30 0 1 3 1 4 13 30 15 32

O OML 120 30 0 1 2 1 9 19 34 20 63

Kigbo OML 121 30 0 0 0 0 27 68 127 73 42

Q OML 120 30 16 29 47 31 9 26 53 29 17


geophysical data, to the point that they are considered viable drilling targets. 2. The GCoS reported here represents an indicative estimate of the probability that drilling this



4. “Net Prospective Resources” in this table are Company’s Working Interest fraction of the Gross resources; they do not represent Company’s actual Net Entitlement under the terms of the sharing agreement between CAMAC and Allied.


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TABLE 0.6

SUMMARY OF UNRISKED PROSPECTIVE RESOURCES (LEADS) NIGERIA AS AT 30th JUNE, 2013

Lead Reservoir

Gross Unrisked Prospective Resources – Leads Best

Estimate

Company Working Interest

(%)

Net Company Unrisked

Prospective Resources – Leads Best

Estimate GCoS

(%)

Oil / Cond

(MMBbl) Gas

(Bscf) Oil /

Cond (MMBbl)

Gas (Bscf)

Kigbo Deep Top Miocene 0 254 30 0 76 10 R Plio / Pleistocene 0 60 30 0 18 34 Onigu Plio / Pleistocene 0 162 30 0 49 15 Eba Lower Pliocene 37 37 30 11 11 15 Songu Pliocene 0 40 30 0 12 42 M Plio / Pleistocene 10 26 30 3 8 11 A East Mid-Late Miocene 53 210 30 16 63 11 A West Mid-Late Miocene 19 95 30 6 28 11 C Mid-Late Miocene 29 133 30 9 40 11 D Mid-Late Miocene 62 281 30 19 84 11 Ereng B Mid-Late Miocene 170 195 30 51 58 9 Ewo Deep Mid Miocene 164 0 30 49 0 9

Notes: 1. Leads are features that are not sufficiently well defined to be drillable, and need further work and/or

data. In general, Leads are significantly more risky than Prospects and therefore volumetric estimates for Leads are only indicative of relative size.

2. The GCoS reported here represents an indicative estimate of the probability that drilling this Lead would result in a discovery, which would warrant the re-classification of that volume as a Contingent Resource. The GCoS value for Contingent Resource is, by definition, unity. These GCoS values have not been arithmetically applied to the designated volumes within this assessment. Thus the volumes are “Unrisked”.


4. “Net Prospective Resources” in this table are Company’s Working Interest fraction of the Gross resources; they do not represent Company’s actual Net Entitlement under the terms of the sharing agreement between CAMAC and Allied.

Blocks A2 and A5, offshore Gambia, contain play potential in Cretaceous sandstones for oil, and two lead areas. In GCA’s view, it is at this stage appropriate only to report prospective resources for one lead, with potential at between 1,800 m and 2,200 m in water depths of 200 m. Prospective Resources (Leads) for Gambia are presented in Table 0.7.


11

TABLE 0.7

SUMMARY OF UNRISKED PROSPECTIVE RESOURCES (LEADS) GAMBIA AS AT 30th JUNE, 2013

Block Lead

Gross Unrisked Prospective

Resources - Leads Best Estimate


(%)


Prospective Resources - Leads

Best Estimate GCoS

(%)

Oil / Cond (MMBbl)

Gas (Bscf)

Oil / Cond

(MMBbl) Gas

(Bscf)

A2 West: Intra Cenomanian. 160 0 100 160 0 5

A2 West: Albian 65 0 100 65 0 5

Notes: 1. Leads are features that are not sufficiently well defined to be drillable, and need further work and/or




Blocks L1B and L16, onshore Kenya, and Blocks L27 and L28, offshore Kenya, contain play potential at a number of reservoir levels for gas and oil, but the blocks require further exploration data acquisition and analysis. No prospective resource volumes can be quantified at this time. The above presented Prospective Resources are GCA’s estimates and have been derived using probabilistic methods. GCoS has also been estimated and reported in the tables above. It is inappropriate to aggregate prospective resources without due consideration of the associated risks, and the dependencies between them. Accordingly, prospective resources are presented on a separate, unrisked basis for each Prospect or Lead.


12

DISCUSSION 1. BACKGROUND TO BLOCKS OML 120 AND 121, NIGERIA Blocks OML 120 and 121 lie on the north-western flank of the prolific, offshore Niger Delta. The blocks are some 60 km from the Nigerian shore line, in moderate water depths between 100 and 900 m (Figure 1.1). The combined total area of the two blocks is 1,807.9 km2. OPL 210 was awarded to Allied Energy 1992 and subsequently converted to OMLs 120 and 121 granted with a 20 year period, beginning 27th February, 2001. These licences currently operate as tax and royalty licence agreements with the state as there is no state participation. On 22nd July, 2005 Allied executed a Production Sharing Arrangement (PSA) with ENI/Agip, where ENI/Agip was established as Operating Contractor, with a 40 % participating interest. In June 2012, CAMAC Energy acquired ENI/Agip’s interest in OMLs 120 & 121. CAMAC is the operator with 30%, under a technical agreement with Allied, while Allied has 70% working interest. Immediately to the west of OML 120 is OML 133, containing the Erha and Bosi complex of oil and gas fields, reportedly containing 495 MMBbl and 400 MMBbl of recoverable resource respectively. More widely, OMLs 120 and 121 lie in a regional north-west to south-east fairway of producing fields, including the Abo Field to the north and the Oberan and Bonga Fields to the south (Figure 1.1). All of the major hydrocarbon discoveries in the vicinity are understood to be in sandstones of Miocene age.


13

FIGURE 1.1

LOCATION MAP FOR CAMAC NIGERIAN ASSETS

OML 120

OML 121

Source: Deloittes


14

2. GEOLOGICAL SETTING

OML 120 and 121 are in the Diapiric Zone of the offshore Niger Delta, where structure is dominated by gravity-driven extensional faults that sole out into deep overpressured shales. Potential traps are created in both the fault footwalls and hanging-walls, modified by upward diapiric movement of mobile mudstone, and with a local stratigraphic component. The area lacks the compressional structures, which characterise the deeper waters to the southwest in the Inner and Outer Fold and Thrust Belts. Growth of the mud diapirs can be shown to be episodic through the Late Tertiary to Recent and exerted a control over palaeobathymetry and consequent sand deposition. Potential sandstone reservoirs occur in the distal portion of the Agbada Formation/depobelt and are of Miocene to Pliocene age (Figure 2.1). They were deposited in a deep-water, slope to basinal setting via sediment gravity flows. Sand deposition is in part relatively unconfined, in laterally coalescing fan bodies, and partly in confined canyon-fills. Changes in depositional styles can be related to evolution of the basin. The principal reservoir intervals relevant to the discoveries and prospects are as follows: • Pliocene: A major canyon-forming event took place during the early part of the

Late Pliocene that cut down in places through to the top of the Miocene. At least three major east-west trending incised systems were created, which were the foci of subsequent transgressive backfilling by confined, amalgamated and stacked submarine channel systems. One example of this type of system forms the reservoir at the Oyo field, and other prospective systems have been identified.

• Upper Miocene (?Messinian): Sandstones of this age are relatively extensive and

were deposited in coalescing fan systems localised in the bathymetric depressions between the major mud diapirs. There is some evidence of channelized sand bodies near the top of this interval, especially in the north of OML 120.

• Upper Miocene (?Tortonian to Lower Messinian): Sand deposition was relatively

sparse in the east of the area, with only minor meandering channel systems punctuating an otherwise mud-dominated section, but a series of slope fan and channel sand systems can be identified in the west of the area. These are believed to correlate with the main reservoir zone at the Erha Field, immediately to the west of OML 120, in OML 133.

• Middle Miocene (Langhian to Serravalian): Regional mapping at this level is

uncertain, but distinct channelized sandstones occur in the north and west of the area.


15

FIGURE 2.1

CHRONOSTRATIGRAPHIC DIAGRAM FOR THE NORTHWEST OFFSHORE NIGER DELTA

Seal is provided by mudstones within the fan and channel complexes and by the more major and transgressive mudstones that cap each group of sandstones. Of great significance to the prospectivity of Blocks OML 120 and 121 is the potential creation of cross-fault seals, both in upthrown and downthrown fault blocks, by juxtaposition of sandstone reservoirs against mud-rich intervals and/or the creation of mud smears within the fault planes.

CRETACEOUS

OLI

GO

CEN

E

CHATTIAN

AQUITANIAN

BURDIGALIAN

LANGHIAN

SERRAVALL

MESSNIAN

TORTONIAN

GELASIAN

PIACENZIAN

ZANCLEAN

Intra Late Pliocene

Top Early Pliocene

Top Miocene

Intra Late Miocene

Near Top Middle Miocene

Near Top Early Miocene

Intra Oligocene Unc.

Pre-Shales

M I

O C

E N

EP

LIO

CE

NE

My AGE

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

1

PLE

IST-

OC

EN

E

CALABRIANIONIAN

Marine Shales (Akata Fm.)

Channel & Fan Systems

Mud Diapirs

Modified After CAMAC


16

Hydrocarbon sourcing is inferred from the Akata Formation mudstones of Eocene to Oligocene age. These units are not penetrated in OML 120 and 121, but regional modelling suggests a mixed charge of oil and gas as a result of mixed source rock quality and of varying maturity. Thermal maturity is modelled to increase south-eastwards, such that a predominantly gas charge is expected for the prospects in the east of OML 121 and a mixed oil and gas charge is expected elsewhere. There is locally evidence from direct hydrocarbon indicators (DHI) from the seismic data of the precise hydrocarbon phase present, which confirms a mixed hydrocarbon charge, including amplitudes and flat spots proven by drilling at Oyo field. Hydrocarbon sourcing has been continuous and dynamic through the Late Tertiary to Recent, amid ongoing structuration. There is, thus, evidence for hydrocarbon loss and seepage to shallow levels and at the sea floor.


17

3. EXPLORATION HISTORY AND GEOPHYSICAL DATABASE: OML 120 AND 121

A sparse 2D seismic data set (Figure 3.1) was acquired over OMLs 120 and 121, from 1991 to 1993. These data cover the majority of the licences, with a line spacing of approximately 2.5 km, though denser in some limited areas. The quality of the 2D data is variable and appears to suffer from some processing issues, such as multiples. Due to the existence of multiple 3D surveys covering the licences, the 2D data were not used during this study.

FIGURE 3.1

SEISMIC DATA COVERAGE AND EXPLORATION WELLS OML 120 AND 121


18

Three surveys provide nearly complete 3D seismic coverage of OML 120 & OML 121. From February to March in 1994 the Oyo 3D seismic survey was acquired over the central and eastern portions of OML 120, the survey covers an area of 450 km2 and was acquired by Western-Geco (Figure 3.1). This survey was used for the interpretation and delineation of the Oyo field, prior to its successful drilling in 1995 (section 4.1). This survey is of good quality, with a consistent amplitude and frequency response throughout. Fluid effects can be observed on the seismic data at the Oyo field and various seismic attributes can and have been used to help define and characterise the field. Faults are imaged well, key seismic reflectors are consistent and map able over the majority of the survey. Mud/shale diapirs are represented with a chaotic internal seismic facies. Several data types have been generated by CAMAC and are present within the seismic interpretation package (IHS Kingdom). These include various time re-processed volumes, Pre-Stack Depth Migration (PSDM) volumes and Amplitude Variation with Offset (AVO) volumes. Limited information was supplied with the supplementary data types and so these were not used to any great extent by GCA during its evaluation of the Oyo field. This survey is SEG normal polarity and zero phase. Agip acquired a 900 km2 3D survey (Figure 3.1), to image the western areas of OML 120 and OML 121 from late 2004 to early 2005. When these data are compared to the 1994 ‘Oyo’ and 2008 ‘New’ seismic surveys the data appear to be poorer quality with a generally lower resolution. The frequency content of the seismic data is lower and the amplitude does not appear to be as consistent. This is especially an issue beneath large faults or close to shale diapirs, where the resolution is poor to the extent where it is not possible to map seismic reflections with confidence. However, the coverage and resolution provided by this survey is a vast improvement over the pre-existing 2D survey data. CAMAC has generated numerous seismic attribute volumes from the original Kirchoff PSTM processing. GCA concentrated of the PSTM data during this study. This survey is SEG reverse polarity and zero phase. Oyo-1 was drilled by Statoil in 1995 finding oil and free gas within Pliocene age deep water sands. Details of this well and further appraisal drilling on the Oyo Central and subsequent discovery of Oyo West field are described in Section 4.1 below. In 1996 the Ewo-1 well was drilled by Statoil (Table 3.1 and Figure 3.1) towards the centre of OML 120, targeting Middle Miocene (Serravalian) aged reservoir sandstones. The Ewo-1 well did not reach its intended target, due to technical issues and was plugged and abandoned in upper Miocene sandstones, where it encountered a thin 7.5 m zone containing oil shows. The shows were untested.

TABLE 3.1

PREVIOUS EXPLORATION WELLS

Well Licence Operator Year Result TD (m)

Ebolibo-1 OML 121 ENI 2007 Gas discovery in Pleistocene A098 to A102 sandstones. 1,912

Ewo-1 OML 120 Statoil 1996 Oil show in Upper Miocene sandstones 2,550

The Ebolibo-1 well was drilled by ENI in 2007 (Table 3.1 and Figure 3.1) in the far south east of OML 121, to test a seismically defined, faulted 4-way dip closed structure. The discovery was supported by strong seismic amplitudes, which shut-off down-dip in


19

coincidence with structure contours. The Ebolibo-1 well encountered nearly 30 m of gas in the Pleistocene section. The discovery was considered sub-economic and plugged and abandoned. In late 2008 and early 2009 Agip (through Western-Geco) acquired an 860 km2 3D seismic survey, covering the south west of OML 120 and the central and eastern areas of OML 121. This ‘New’ survey is similar to the 1994 ‘Oyo’ survey in that it is good quality, with a consistent amplitude and frequency response throughout. Fluid effects can be observed on the seismic data (for example at the Ebolibo discovery and at similar prospects in the vicinity). Faults are resolved well, seismic reflectors are consistent and map able within the licence area. Mud/shale diapirs are represented with a chaotic internal seismic facies. Several data types have been generated by CAMAC and are present within the seismic interpretation package (IHS Kingdom). These include various time re-processed volumes, PSDM volumes and numerous seismic attribute volumes. Limited information was supplied with the supplementary data types and so these were not used to any great extent by GCA during its evaluation of the Oyo field. This survey is SEG reverse polarity and zero phase. In general the seismic interpretation is reasonable and seems to follow the seismic reflections. However, in certain areas the structure becomes difficult to interpret. In most cases the top and the base of the reservoir has been picked on time migrated data, in addition to some more regional surfaces, which can be difficult to pick from one survey to another due to consistency issues. The seismic dataset would benefit from a consistent approach to the processing, which would enable more confident interpretations to be made away from well control than are currently possible. CAMAC has converted their time surfaces to depth using a simple layer-cake conversion method, which utilises velocity surveys from existing and relevant well data. Due to the quality of the 3D seismic data it has been possible to extract various seismic attributes from certain horizons or time envelopes through the data. CAMAC has extensively used this approach in the interpretation of the Oyo field and the delineation of further prospects, throughout the OML 120 and OML 121 licences. GCA has been able re-create and in some cases refine seismic attribute extractions where necessary, in order to help validate certain features of interest.

4. OYO FIELD

4.1 History and Introduction The Oyo Central field was discovered by Oyo-1 in 1995. Oyo 1 penetrated the T1A reservoir sands at 1,710 m MD and encountered 49 m (gross) of gas and 46 m (gross) of oil in amalgamated channel and associated sandstones of Pliocene age. Two sidetrack holes (Oyo-1 ST1 and Oyo-1 ST2) were drilled due to stuck pipe and stuck casing. The Oyo 1 well continued through the T1A reservoir and encountered a second potential reservoir sand, the T1B, at approximately 1,879 m where it logged approximately 5-6 m of oil. The Oyo-1 well was tested in the oil leg of the T1A reservoir producing approximately 1,400 bopd of 35° API crude oil before sanding up. The T1B interval was not tested by Oyo 1 or in any subsequent wells drilled into the T1B. Subsequent drilling focussed on the Oyo West field with the drilling of Oyo-2 in 2006. This sought to penetrate the T1A reservoir, which had been interpreted to be continuous from Oyo Central as, although Oyo West is separated by a structural low from Oyo Central, it is broadly correlative and has a similar seismic character as the Oyo Central


20

sands. The Oyo-2 well encountered sand at approximately 1,710 m MD which logged 13 m of oil in two separate pools. Oyo-3 wwas drilled in February, 2007 targeting the upper portion of the Oyo West structure. Oyo-3 encountered three separate sand bodies logging a total of 6 m (net) of gas and 26 m (net) of oil. These sand bodies are interpreted to be part of two separate reservoir sands from that encountered in the Oyo-2 well. Drilling returned to Oyo Central, the Oyo-4 well was drilled in December, 2007 and encountered the T1A hydrocarbon section seen 12 years earlier by the Oyo 1 well. The Oyo 4 well further established the lateral extent of the T1A sand and encountered the T1B but logged only water. Oyo 4 was completed in 2009 in the T1A as a gas injection well. In 2009, the Oyo 5 was drilled at Oyo Central and completed as a horizontal well in the oil leg of the T1A reservoir. Following the installation of a FPSO in 2009, Oyo 5 was brought online at about 9,500 bopd for the first month of production and remains on production at high gas-oil rate. The three sand bodies at Oyo West were termed the Oyo Main reservoir by CAMAC, and were subsequently drilled and completed by the Oyo 6 horizontal well in 2009 and brought on production. Oyo 6 was brought online at approximately 6,300 bopd in the first month of production and remains on production at high water cut to the present day. 4.2 Geology The Oyo Fields (Central and West) are located in east-central Block 120, in approximately 500 m of water. Unusually for western offshore Nigeria, they comprise producing oil reservoirs of Pliocene (Lower or possibly earliest Upper) age, in canyon-fill sediments of amalgamated submarine channel sandstones, with associated off channel facies. Regional mapping of the channel sands shows a series of such fairways and the sandstones at Oyo Central and Oyo West are broadly part of the same sedimentary system which can be observed continuing westward to the O prospect (see section 7.2). The fields lie in the Diapiric Zone of the offshore Niger Delta and the Oyo Central field is underlain by a mud diapir, active episodically from the Late Miocene to the Recent. Diapiric growth has created a simple four-way dip closure, although this is bisected by an arcuate fault zone comprising several fault segments running through the crest of the field (Figure 4.1). Although this zone is a conspicuous, continuous feature on the field maps, it is in reality a zone of several antithetic faults to the major normal fault systems to east and south. It does not radically alter the depth structure of the reservoir. It is uncertain whether it acts to significantly compartmentalise the reservoir, but at this stage reserve evaluation recognises the two distinct east and west fault blocks. All of the wells drilled to date have been in the western fault compartment. The trap at Oyo West is slightly more complex, as it lies on the southern flank of a diapiric culmination and thus there is an element of stratigraphic closure on the north of the field at the margins of the canyon-fill (Figure 4.2). Seals are provided by the mudstones, which overlie the channel sandstones at Oyo Central, but at Oyo West, in addition, there are intraformational and/or fault seals that create at least three separate hydrocarbon pools at. Tentatively, it is the lowermost, seen at Oyo-2, which correlates with the reservoir interval at Oyo Central. The pools at Oyo-3 and at the Oyo-6 wells are stratigraphically younger.


21

Hydrocarbon charge is provided by the underlying Akata Formation (Eocene). Modelling suggests that this has generated both oil, commencing in the Miocene, but with increasing burial and gas generation through to the present day, to create the mixed hydrocarbon phase seen in the fields.

FIGURE 4.1

OYO CENTRAL CONTOURED DEPTH STRUCTURE MAP TOP T1A RESERVOIR


22

FIGURE 4.2

OYO WEST CONTOURED DEPTH STRUCTURE TOP UNIT 4 RESERVOIR AND RMS AMPLITUDES REPRESENTING UNIT 3/4 RESERVOIR UNIT

4.3 Geophysics

The Oyo 3D Western-Geco survey covers the entirety of the Oyo field area. CAMAC has presented the full stack dataset, along with near and far stack data volumes and other derivative datasets. All relevant data have been used by GCA in its review of the definition of the field. The seismic database is discussed in more detail in section 3. The following seismic horizons have been picked over the Oyo field area: • Oyo Central

o Top T1A sandstone o Top T1B sandstone o Top Miocene

• Oyo West

o Top Unit 4, representing top of Pliocene reservoir sand package.

0 0.5 1 km

Limit of Oyo West Unit 3/4 hydrocarbon

pool

Trap closure probably controlled by structural spill

point

Updip limit at edge of canyon-fill sandstones


23

Illustrative seismic panels for Oyo Central and Oyo West are presented in Figures 4.3 and 4.4. Interpretations have been made in time, and depth surfaces have been created using the time-depth velocity relationships from the Oyo wells, in particular VSP data from Oyo-4 for Oyo Central and for Oyo-3 for Oyo West.

FIGURE 4.3

VERTICAL SEISMIC SECTION THROUGH OYO CENTRAL FIELD WITH CONTOURED DEPTH MAP


24

FIGURE 4.4

VERTICAL SEISMIC SECTION THROUGH OYO WEST FIELD WITH CONTOURED DEPTH STRUCTURE MAP

4.4 Reservoir Geology

Details of the variation in sedimentary and reservoir geology have been reviewed in order to better calibrate likely future well performance. In addition to the seismic data, log data were available for the following wells: • Oyo Central:

o Oyo-1 o Oyo-1ST1 o Oyo-1ST2 o Oyo-4 o Oyo-5ADIR o Oyo-5ADIRST


25

• Oyo West o Oyo-2DIR o Oyo-3 o Oyo-3DIR o Oyo-6DIR o Oyo-6DIRST1 o Oyo-6DIRST2

It is clear from study of the sedimentary facies in the wells and their representation in the seismic amplitude signatures that there is considerable variation in the likely reservoir thickness and quality within the overall envelope of the field. On this basis, the Oyo Central field has been divided into a series of domains of common expected reservoir facies (Figure 4.5) and these have been used to aid assessment of hydrocarbon volumes. Figure 4.5 summarises two general domains within the fairway of the Oyo Central Field. The zone highlighted in green represents the axis of two submarine channel tributaries, which are inferred to contain the optimum stacked, laterally and vertically continuous reservoir facies. Porosity is expected to be approximately 30% and net/gross reservoir thickness ratios are around 0.6. In yellow are areas, which are inferred to consist of sandstones deposited adjacent to the main channels and/or minor channel systems above the level of the main reservoir. These are inferred to be of lower quality and possibly less well connected than the main channels. Porosity is expected to be marginally less than the channel facies, but more significantly net/gross ratio will range down to around 0.35. The difference can be seen in Figure 4.3, where strongly-defined reservoir sands, with a distinct seismic horizon interpreted to represent the hydrocarbon-water contact, pass north-eastward into an area of less distinct seismic signature. Although reservoir quality may vary, both of these domains contribute to the producible hydrocarbon volume of the field. To the north and south of the main fairway (Figure 4.5) are parts of the trap, which are less well-defined structurally, but also not interpreted to contain the same reservoir system as the axis of the field. Sandstone units here may be too thin to provide a clear seismic response and are inferred as representing the sedimentary section lateral to the main channel systems. At this stage, a small in-place hydrocarbon resource is assigned to these areas, but no wells are currently targeted and no reserves are allocated to them. It is emphasised that the interpretations made are the best that can be derived from the available dataset, but that additional wells will greatly improve the understanding of the reservoir models and the calibration of the seismic response.


26

FIGURE 4.5

OYO CENTRAL RMS AMPLITUDES INTERVAL FROM 30 MSEC ABOVE TO 80 MSEC BELOW TOP T1A RESERVOIR AND DEPTH STRUCTURE CONTOURS

AT TOP T1A RESERVOIR

4.5 Field Development, Cost and Schedule 4.5.1 Overview

The Oyo Central and Oyo West fields came on production in December, 2009 from the Oyo-5 and Oyo-6 wells respectively, supported by gas injection into Oyo-4. As of 16th July, 2013, both oil wells continued to flow, well Oyo-5 at high gas-oil ratio (>12,000 Scf/Bbl) and Oyo-6 at high water cut (85%); however on that date no gas injection into Oyo-4 was occurring, with all produced gas temporarily flared. These wells are connected to the Armada Perdana FPSO, which is on contract to the end of 2013. Thereafter, GCA has been informed that the vessel is likely to be decommissioned from the field (at no cost to CAMAC) and is likely to be replaced with a refurbished FPSO, the Teekay Petrojarl I in mid-late 2014. CAMAC informed GCA that the Joint Venture has signed a preliminary agreement leading to a planned Memorandum of Understanding (MOU) with experienced FPSO owner Teekay for the provision of the Petrojarl for a 5 year minimum term with options for up to three years extension. Once the Petrojarl is in place, two


27

new producer wells (Oyo-7,-8) will be connected to the Petrojarl followed by re-connection of gas injection well Oyo-4, with options for 4 further Oyo Central wells (wells -9 -10, -11 and -12) in later years. Well Oyo-6 will be reconnected and resume production in Nov 2014. Well Oyo-5 is currently expected to cease production at the end of 2013 and its wellhead and flow-line will be recovered and refurbished for use on the new wells. Long lead time items are already on order and will be available from end 2013. Oyo-9 is expected to be drilled in late 2014 and, assuming wells -10 through -12 are drilled, all four would be completed and placed on production by August, 2015 in a single campaign of well hook-up. The addition of a chilling unit to the new FPSO is planned in order to optimize condensate recovery from post-separator gas production.

4.5.2 Capital and Operating Costs, Development Schedule

Gross CAPEX in 2013 is estimated to be $80.8 MM including the vertical portion of well Oyo-7 plus engineering studies for further field development including engineering and design of three new horizontal producing wells and the redevelopment of the field using the Petrojarl FPSO. GCA understands that CAMAC will not participate in the costs for Oyo-7 and in exchange will retain a revenue interest in production from this well (similar to its position in wells -5 and -6). CAPEX in 2014 is currently estimated to be US$194 MM including completion of the Oyo-7 lateral and drilling/completing Oyo-8 plus subsea installation and connection of the two new wells and Oyo-4 gas injector. There is a cost estimate of US$29 MM to suspend the three existing wells, flush flow lines and retrieve and refurbish them as part of the redevelopment plan. All costs associated with demobilising the existing FPSO vessel are not for CAMAC’s account. It is probable that Oyo-9 may be drilled in the latter part of 2014 or early in 2015 depending on rig mobilisation. If Oyo-9 slips into 2015, then capital costs for this well and its completion are estimated to be US$87 MM. In the event that wells Oyo-10, -11 and -12 (GCA 3P scenario) are sanctioned in late 2014, planning and long lead time items will boost 2014 CAPEX to US$210 MM and 2015 costs to US$357 MM including drilling and completing these 3 wells plus Oyo-9. Gross OPEX for 2013 is estimated to be US$90 MM for the full year, with US$45 MM due post the effective date of 30th June 2013. In 2014, the Petrojarl FPSO should be under contract for 3 months, which together with abandonment cost sinking fund means total OPEX for the will be US$34 MM. In a full year, OPEX for the FPSO with full Teekay support plus $6 MM per year abandonment contribution are estimated to be US$109 MM per year.

4.5.3 Development of Adjacent Discoveries There are several small gas discoveries near to the Oyo fields, but there are no current plans to develop any of them as there is no gas export solution. CAMAC has identified significant exploration potential for oil prospects (Section 7 of this report) which could be tied back to the Oyo Field FPSO in the future.


28

4.6 Technical Assessment 4.6.1 FPSO and Marine

The planned replacement FPSO for the longer term development of Oyo fields is the Teekay Petrojarl I, built in 1986 to a Golar-Nor Offshore design by NKK of Japan. It is designed to handle a wide range of different well stream compositions and flow rates, including gas and water injection. It was originally designed for harsh environments of the North Sea, hence it should easily be able to manage the more benign conditions offshore Nigeria. It has successfully operated on a wide range of UK and Norwegian oil fields at rates up to 46,000 bopd (source Teekay). The vessel is 215 m long, 32 m wide and has a draught of 12 m; current deadweight is 31,473 tons and it has storage capacity for 190,000 Bbl of oil. It is capable of handling 46,000 bopd, 47,000 bwpd and up to 52,000 bwpd for injection based on typical light North Sea crude oils, similar to those found at Oyo. Once a firm contract is signed, Teekay will upgrade existing gas compressor capacity to handle 60 MMscfd of gas, dehydrate and recover NGL/condensate from the same volumes of gas and upgrade power generation. Gas will be re-injected for pressure maintenance and, if required for gas-lift support for high water cut well operations. Costs for the FPSO refurbishment and upgrade will be recovered by Teekay from the bare boat charter rate for the vessel. CAPEX associated with installation of the replacement FPSO is paid for by the equity partners in the field, covering installation of flow-lines, well-heads and anchoring of the vessel. Teekay will provide the vessel on a bare boat charter for a fee per day and also provide operations and maintenance and support vessels for a separate fee to provide an all-inclusive support role. The vessel is expected to be upgraded and then arrive on location in the third quarter of 2014 with well hook-up and commissioning in September-October 2014, except for Oyo-9 which is planned to be on stream in August 2015. Subject to the performance of Oyo-7 and -8, three further wells, Oyo-10, -11 and -12, may be drilled on the eastern flank of the structure and placed on stream in late 2015.

4.6.2 Wells and Drilling

Wells Oyo- 5 and Oyo-6 (both horizontal wells) are currently on production with Oyo-4 available for gas injection. GCA understands that Oyo-4 has a minor hydraulics leak and hence no gas injection is currently taking place. The wellhead will be recovered at the end of 2013 when the existing FPSO departs and all seals will be checked and replaced prior to its re-installation in October 2104. Development well Oyo-7 is due to be spudded as a vertical appraisal well in Q3 2013, with the objective of evaluating deeper pool potential below the main Oyo Central pay zone and also confirming current status of gas-oil and oil-water contacts from the main pay producing at Oyo-5. The well will likely take 50-60 days to drill, log, case and cement and then it will be suspended until mid-2014. At that point, plans are for it to be re-entered and a horizontal well bore to be drilled east of the current gas injection well Oyo-4 and completed as a 500 m long cased-hole oil producer. It is GCA’s understanding that this and other new producers are expected to have a passive inflow control (“intelligent”) completion, which will be designed to minimise early gas breakthrough from the gas cap and


29

hence maximise oil recovery at moderate gas-oil ratios. In any event, Oyo-7 is expecting to be operated in a more conservative pressure drawdown than Oyo-5 to help conserve reservoir energy and limit gas cusping during early well life. Extensive well-bore planning has been undertaken, including pore-pressure prediction and avoidance of shallow gas hazards incorporated into selection gas casing design and planned mud weights. The main Oyo Central reservoir is expected to be slightly pressure depleted, whilst the deeper targets beneath may involve a modest level of overpressure hence an intermediate casing string will be set before drilling into the deeper Miocene objective. Planned T.D. for Oyo-7 is 2,466 m MD. Development well Oyo-8 is expected to be a similar design to Oyo-7 and will be targeting efficiently draining the western portion of Oyo Central field. As currently planned, Oyo-8 will be drilled as a main sand producer without penetrating the deeper targets planned for Oyo-7. Both wells should be connected to the Petrojarl in Q3 2014, with surplus gas re-injected into the existing Oyo-4 injection well. Oyo-9 is currently planned for drilling in late 2014 to early 2015 and to be connected to the field by mid-2015. It is also planned as a main sand development well, in this case draining the crestal area of the field south and southeast of wells -5 and -4 (see Figure 4.8). Wells Oyo-10, -11 and -12 may be drilled on the undrilled eastern flank of the structure in 2015.

4.6.3 Subsea Architecture All the existing wells were completed as subsea wells and individually tied back to the FPSO by means of flexible flow-lines. The existing dynamic umbilical and termination assembly (UTA) will be recovered and re-used for the new FPSO. All pipeline and riser systems are rated for 5,000 psi (345 bar) internal pressure and each production well is equipped with a 10,000 psi rated horizontal tree. Each well is controlled via electro-hydraulic umbilical connection using a Cobra Head Connection System. The umbilical is of continuous length and has a free hanging design. A schematic of the field subsea layout is shown in Figure 4.6.

FIGURE 4.6

OYO FIELD: SCHEMATIC OF SUB-SEA LAYOUT


30

4.7 Development Uncertainties Critical reservoir uncertainties at this time are the lateral extent of individual sand bodies within the main Oyo Central reservoir, particularly the degree of sand continuity between lateral producers located within the oil zone and free gas within the gas cap. Production logging on well Oyo-5 clearly shows gas breakthrough at the heel (the part of the lateral nearest the vertical portion of the well); what is less certain is the impact of poor cement bonds and also the high draw-down that was employed by the previous operator at well start-up. Reduced draw-down and potential benefits of intelligent well completions have been factored in to the forward development plan. There are no direct measurements of the present day gas-oil and oil-water contacts within Oyo Central field; however should be rectified once the Oyo-7 vertical appraisal well penetrates this interval in the next couple of months. If the original contacts remain broadly similar to the original conditions, implying only local gas cusping around well -5, then it is likely that lateral portion of wells -7, -8 and -9 will be placed in the middle of the original oil column. 4.8 Safety and Environmental GCA has been informed by CAMAC that there is government consent to continue oil production and gas flaring for the remainder of 2013, on the understanding that gas re-injection will be re-instated at the start of redevelopment in 2014. Teekay is a very experienced FPSO operator who will be providing day to day operations management of all vessels and topside operations. The forward field development plans for Oyo and Oyo West include provision for full treatment of all produced water clean-up to permit safe overboard disposal. There is provision to handle process and re-inject produced gas up to a 60 MMscfd limit, presuming that the existing gas injection well -04 can be further stimulated to handle this volume of injected gas. During the 2014 temporary shut-down, existing flow lines will be purged of oil and retrieved and refurbished prior to operations to re-connect them to the Petrojarl vessel in Q3 2014. Similarly, at the end of field life, it is likely that all flow lines and subsea trees will be retrieved (after flushing with seawater) and all wells permanently abandoned with a series of cement plugs. There is an annual “sinking fund” contribution to cover end of field abandonment costs, treated as operating costs for tax calculation purposes. It is possible that some of the subsea equipment could be refurbished and re-used on any future oil discoveries adjacent to the Oyo Fields. 4.9 Oyo Central 4.9.1 Oil in Place

Hydrocarbons initially in place have been estimated using the seismic mapping and the lithological and fluid parameters from the wells drilled. This has allowed a validation of the production performance and future production profiles used to estimate hydrocarbon reserves. The in-place volumes are summarised in Table 4.1.


31

TABLE 4.1

HYDROCARBONS INITIALLY IN PLACE OYO CENTRAL FIELD

Domain

Hydrocarbons Initially in Place (Best Estimate)

Oil (MMBbl)

Gas (Bscf)

Oil leg Condensate Free gas cap

Dissolved gas

Principal fairway, western fault block 55.9 0.5 41.1 35.6

Principal fairway, eastern fault block 40.7 0.4 30.4 25.9

Additional hydrocarbons in marginal facies, western fault block

7.4 0.0 0.9 4.7

Additional hydrocarbons in marginal facies, eastern fault block

4.4 0.0 1.4 2.8

Total Western Fault Block 63.8 46.7 Total Eastern Fault Block 45.5 34.6

4.9.2 Reserves Estimation

Estimations of reserves are based on Decline Curve Analysis (DCA), after an older dynamic reservoir simulation model had been found inadequate for prediction purposes. Uncertainty exists with regard to connected volumes in this reservoir, and a new well, Oyo-7, due to be drilled within the next few months, should increase the overall understanding of the geology, reducing the uncertainty. Until the results from the new well are available, the GCA forecasts take into account the risk and uncertainty.

4.9.3 Proved Reserves (1P)

Proved Developed Production The only well currently producing in the Oyo Central field is the Oyo-5 AST, which produces from the T1A sand. The oil is light, with a 35° API gravity and a GOR of 620.4 scf/Bbl (110.5 sm3/sm3). Produced gas is re-injected into a crestal well, Oyo-4. Both water and gas break-through occurred relatively early and remedial actions have been taken by the current operator. Figure 4.7 shows the historical performance for the well, along with GCA’s 1P forecast.


32

FIGURE 4.7

OYO NO. 5A ST PERFORMANCE AND 1P FORECAST

Current pressure decline in this reservoir is around 400 psi over 4 years (see Figure 4.8), an indication of some pressure support by small aquifer, and gas injection at a rate less than voidage replacement. The well has a defined decline and was producing at an increasing water cut and GOR until July 2012 (month 31) when a workover was done in order to reduce the water and gas rates. Oil production improved for a short period and has begun to decline again. Initial decline rate was found to be 83% with a hyperbolic decline exponent of 0.8. The same decline trend has been assumed to continue in the 1P case, with a current nominal decline factor (d1) of 4% imposed on the current production rate of 1,005 bopd (30,590 barrels of oil per month). This well is expected to continue production until the end of 2013 when the current FPSO vessel is expected to leave and be replaced in Q3 2014 by a different vessel. However, due to economic cost constraints, GCA understands the Oyo-5 is currently not going to be recompleted for production in 2014 and the wellhead will re-utilized by a new well, Oyo-7, and thus reserves for this well are only up to the end of 2013.

0

10

20

30

40

50

60

1.0

10.0

100.0

1,000.0

0 20 40 60 80 100

GO

R (M

scf/s

tb),

WC

T (%

)

Oil

Prod

uctio

n (M

bopm

)

Time (Months)

OYO-5 History 1P FitProduction Prediction, BOPM. GOR (history)WCT (history)

2012 Workover


33

FIGURE 4.8

OYO-5 FLOWING BOTTOM-HOLE PRESSURE

Proved Undeveloped Production Three new wells have been scheduled to be drilled in Oyo Central: wells Oyo-7, Oyo-8 and Oyo-9 (see Figure 4.9). Oyo-7 and Oyo-8 are scheduled to be drilled in 2014, with start-up October 2014. Oyo-9 is due for start-up in August 2015. All three wells are to produce from the T1A sands, and thus a reasonable certainty exists of finding reservoir with high confidence of commerciality. The following assumptions were made during the performance prediction analysis: a) production strategies would be based on improved reservoir management as

expressed and evident in the supplied business plan (rate management to control gas cusping and water coning issues, wells with inflow control devices (ICD), sand control, FPSO upgrade);

b) initial well capabilities would be similar to that of Oyo-5 prior to gas and water coning issues, provided that the planned wells are horizontal, and similar to the existing wells, as being planned;

c) initial rates and decline factors would be based on reservoir quality and accessible volumes, at present predicted from seismic interpretation. Since a higher degree of uncertainty in the seismic interpretation had been in the region of the proposed Oyo-9 location, the chosen DCA parameters for this well are more pessimistic;

d) pressure support to the new wells will improve in the absence of Oyo-5, which produced at high GOR and WCT; and

2,000

2,200

2,400

2,600

2,800

3,000

3,200

Flow

ing

Bot

tom

-hol

e Pr

essu

re (p

si)

datum depth = 1742.7 m TVDSS


34

e) condensates will be recovered from all gas produced (associated gas and gas from the gascap) in the order of 750 stb/d initially, declining to 500 stb/d after two years. This assumption is based on assuming an initial condensate-gas ratio of 11-16 stb/MMscf, levelling off as the injected lean gas is recycled.

Actual reserve volumes were determined by economic limit testing. For the Proved Undeveloped projected production profiles, GCA has used initial rates and initial nominal decline factors of 7,000 bopd and 10% (Oyo-7), 7,500 bopd and 8% (Oyo-8), and 4,500 bopd with 20% (Oyo-9). Hyperbolic exponents were 0.8 in all cases. The initial nominal decline rate for well Oyo-5, as fitted to historical data, is 22% in the proved case, and the lower decline rate assumptions for the new wells are based on the assumption of improved reservoir management.

FIGURE 4.9

LOCATION OF OYO WELL NOS. 7, 8 AND 9

4.9.4 Proved plus Probable (2P)

The Proved plus Probable reserve performance profiles were forecast with improved decline characteristics, as compared to those for PUD reserves. The initial rates for Oyo-7, -8 and -9 were set to 7,500, 8,000 and 5,000 bopd


35

respectively, with initial nominal decline rates for Oyo-5, and Oyo-7 through to Oyo-9 of 2.8%, 8%, 7% and 18%, respectively. Again, although the initial nominal decline rate for well Oyo-5, as fitted to historical data, had been much higher (18% in 2P case), the lower decline rate assumptions for the new wells are based on the lower initial production rates. Hyperbolic exponents of 0.8 were used for all wells. Oyo-5 contribution beyond 2013 was zero, due to re-utilization of its wellhead. Again, DCA parameters were selected by considering predicted accessible volumes in place combined with Oyo-5’s historical performance. Actual reserve volumes were determined by economic limit testing and a more optimistic field shut-down period of 8 months instead of 9 months...

4.9.5 Proved plus Probable plus Possible (3P)

The Proved plus Probable plus Possible reserves included the planned new wells in Oyo Central, east from the main fault, Oyo-10, Oyo-11 and Oyo-12. All three wells are scheduled for start-up in August 2015. Although no exploration wells had penetrated the section east of the fault, a geologically reasonable assumption would be that the fault is non-sealing, based on the depositional model and the low fault displacement, as interpreted from seismic data, and reservoir geology. Well paths for the three additional eastern wells had not been provided, but it is assumed that these would be horizontal wells, similar to Oyo-5. The performance forecast for these wells were based on (a) the geoscience interpretation of the rock quality and net reservoir thickness in the present proposed well locations (Section 4.4), and (b) the performance history of Oyo-5. The accessible volumes for these three wells were predicted as being lower than that of Oyo-5 due to lower connected reservoir quality, and subsequently, lower initial rates with steeper decline rates were used in estimating the individual recoveries. It has further been assumed that reasonable care would be exercised by the operator to manage the reservoir, in which case lower initial rates could result in lower declines rates. The DCA parameters per well for the 3P case are shown in Table 4.2. Oyo-5 contribution beyond 2013 was zero, due to re-utilization of its wellhead.

TABLE 4.2

DCA PARAMETERS PER WELL FOR THE 3P CASE

Well Initial rate

(Qi) (bopd)

di b

Oyo-5 1,005 0.02 0.85 Oyo-7 8,000 0.08 0.85 Oyo-8 8,500 0.06 0.85 Oyo-9 6,500 0.10 0.85 Oyo-10 7,000 0.15 0.80 Oyo-11 7,000 0.15 0.80 Oyo-12 6,000 0.15 0.80

Figure 4.10 shows the relation of the forecasted production profiles in relation to the Oyo No. 5 A ST well.


36

FIGURE 4.10

PERFORMANCE COMPARISON FOR 1P, 2P, AND 3P

4.10 Oyo West Field 4.10.1 Oil in Place

Oyo West is a complex composite trap comprising at least three individual hydrocarbon pools. The main channel sandstone body appears to be that targeted by the Oyo-6 wells. A best estimate of in-place hydrocarbon volumes has been made for this hydrocarbon pool alone, based on the extent of the seismic amplitudes (Figure 4.2) that define the channel margin and the proven oil-water and gas-oil contacts. Reservoir and fluid properties are as defined by the wells. This volume does not include the additional volumes at shallower levels or in the small additional deeper pool proven at Oyo-2 (see Table 4.3).

TABLE 4.3

HYDROCARBONS INITIALLY IN PLACE OYO WEST FIELD

Domain

Hydrocarbons Initially in Place (Best Estimate) Oil

(MMBbl) Gas

(Bscf) Oil Leg Condensate Free Gas Cap Dissolved Gas

Principal channel fairway 33.5 0.2 12.5 21.3 Total 33.7 33.8

10.0

100.0

1000.0

0 5 10 15 20 25 30 35 40

Oil

Prod

uctio

n (B

OPM

)

Time (Months)

OYO-5 History 1P 2P 3P


37

4.10.2 Proved Reserves (1P)

Proved Developed Producing The only well producing in the Oyo West Field is the Oyo-6 well, which produces from what is referred to as the Main sand. The well produces 27° API oil with a GOR of around 370 to 400 scf/stb (66 to 71 sm3/sm3). The following Figure 4.11 shows the historical flowing bottom-hole pressure and production performance, and Figure 4.12 the DCA forecast for the well. The bottom hole pressure shows good reservoir pressure maintenance for the period 2011 to mid-2012, with a total drop of 600 psi during the 4 years of production. A 10-fold increase in produced GOR is observed and WCT at the end of 2012 was above 80%.

FIGURE 4.11

OYO NO. 6 HISTORICAL PERFORMANCE

1,500

1,700

1,900

2,100

2,300

2,500

2,700

2,900

FLow

ing

Bot

tom

hole

Pre

ssur

e (p

si)

datum depth = 1616 m TVDSS

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

10

100

1000

WC

T (fr

actio

n) a

nd G

OR

(Msc

f/stb

)

Oil

Prod

uctio

n (B

OPM

)

BOPM GOR WCT


38

FIGURE 4.12

1P FORECAST FOR OYO-6

The well has a defined decline until mid-2011 when production plateaued until mid-2012 at which time the decline resumed. No reason for this plateau has been provided. . Initial decline rate was found to be 86% with a hyperbolic decline exponent of 0.8. The same decline trend has been assumed to continue, with the nominal decline factor at end Jun 2013 (di) of 5%. Actual reserves are based on the results of an economic limit test, which is discussed later in the report. Proved Undeveloped

There are no Proved Undeveloped wells scheduled for the Oyo West Field.

4.10.3 Proved plus Probable (2P)

There are no further wells scheduled for the Oyo West Field.. However, a more optimistic prediction of probable production performance of Oyo-6 was based on a nominal decline factor of 3% at the end of Jun 2013, with a hyperbolic decline exponent of 0.8. This is based on the performance history in 2012.

10.0

100.0

1000.0

Oil

Prod

uctio

n (B

OPM

)

BOPM DCA Predicted 2014 onwards


39

4.10.4 Proved plus Probable plus Possible (3P)

There are no further wells scheduled for the Oyo West Field. However a more optimistic forecast for Oyo-6 using a decline factor of2.5%, with the same hyperbolic decline exponent as above. The low decline factors in this field are based on the PVT, indicating slightly higher viscosity oil, which generally delivers lower rates initially, but perform at a lower decline in the long term.

4.11 Contingent Resources No Contingent Resources are assigned in the Oyo Fields. 4.12 Prospective Resources – Deep Pool Potential at Oyo Field As part of the further development of Oyo Field, well Oyo-7 is planned to drill below the producing T1A reservoir to further evaluate oil shows in underlying sands. 4.12.1 T1B Formation

Well Oyo-1ST2 encountered a gross 6 m column of oil shows in argillaceous sandstones at the top of the T1B sandstone (at 1,849m) with an ODT at approximately 1,855 m. There is a thin shale barrier above the T1B sands at this location that separates it from overlying water bearing sands. Results at the other Oyo-1 borehole/sidetracks and the presence of water bearing sands in Oyo-4, where the top of the T1B sandstone is at 1,859 m, suggest 1,855 m is the possible oil water contact. No testing of this interval has been conducted (oil was recovered in an RFT) and the reservoir quality of the drilled hydrocarbon column is poor, but there may be potential for sandstones of better porosity to occur higher on the structure. Although the seismic data quality is poor, mapping of the top T1B sandstone indicates a simple dip closure formed by rollover into growth faults to the south and east of the field, with spill very likely controlled by cross fault leakage, although precise interpretations around the fault are unclear at this stage. The antithetic fault splay, which may influence the main T1A reservoir, does not greatly affect the T1B level, although there is a small part of the closure mapped in the eastern fault block. The consistency of the structural mapping with the OWC defined in the wells allows a low case (P90) to be defined in the western fault block. The most likely case (P50) includes additional pay in the eastern fault block, where there is uncertainty over the interpretation and mapping. A high case (P10) is created by adding an arbitrary additional 10% to the gross rock volume, reflecting the level of uncertainty in the mapping. The sedimentary setting is inferred as being similar to the T1A sandstones, with reservoirs occurring in submarine channels and associated interchannel fan facies. Some variability in quality and lateral continuity is expected within the prospect. Along with the mapping and precise trap size, risk attached to the presence of top sealing shale is the main uncertainty and is the reason for assigning these resources in the prospective category. There is no particular support for the presence of gas within the structure, but there is the possibility of a small gas cap, as in the overlying T1A reservoir. This uncertainty has been reflected in the volume analysis.


40

Current mapping suggests that the proposed Oyo-7 vertical pilot well will intersect the T1B sandstone at a slightly higher level than at Oyo-4 and will further confirm the position of the proposed OWC. Probabilistically derived oil and gas in-place volumes for Oyo T1B reservoir are presented in Table 4.4, with estimated GCoS. Prospective Resources are presented in Tables 0.4 and 0.5.

TABLE 4.4

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES OYO T1B

Prospect Name

Licence Name

Gross Unrisked In Place Volumes GCoS


Oyo T1B OML 120 5 8 12 8 1 5 12 6 64

4.12.2 Upper Miocene

Beneath the producing Pliocene reservoirs at Oyo Field there is additional untested potential within the Miocene section, interpreted to be of Tortonian to Messinian age. Well Oyo-1 ST2 encountered oil shows from a sand at 2,305 m, but unfortunately no logging or further evaluation of this zone was possible. However, ditch cuttings indicate a gross 11 m of oil-bearing sand and structure mapping suggests that this lies near the base of a dip-closed trap to the south of the well (Figure 4.13). In addition there is a similar culmination beneath the north of the field. The nature of the synclinal area separating the northern and southern culminations is unclear, but this may represent a later channel incision, filled with mudstone. A low volumetric case (P90) is defined solely in the southern culmination by the results of the well, allowing for an 11 m hydrocarbon column below that structural level. The best case (P50) includes both the southern and northern culminations as potentially containing hydrocarbons with a contact defined that links them as one continuous hydrocarbon pool. This has a contact approximately 25 m below the level of the Oyo-1 ST2 well. The detail of the seismic correlation within the overall anticline is obscure so the precise maximum potential size of the prospect is unclear, but a high case (P10) can be defined within the limits of the interpretation and mapping with a closure approximately 35 m below the level of the Oyo-1 ST2 well. The mapping of the northern culmination, and nature and extent of the syncline/ channel incision that separates the northern and southern culminations are the key risks attached to extending this prospect beyond the southern culmination and the hydrocarbon column inferred at Oyo-1 ST2. The potential interval is not logged in the area of the field. Reservoir parameters have been used from Oyo-1 ST2 in the Upper Miocene immediately overlying the target zone. The prospect is modelled as containing mainly oil, but the possibility


41

is included of a gas cap above the level of the oil column indicated at Oyo-1 ST2. Fluid parameters are as at the Oyo Field, adjusted as appropriate for depth.

FIGURE 4.13

OYO CENTRAL DEPTH STRUCTURE TOP OYO MIOCENE RESERVOIR AND RMS

AMPLITUDES (FAR STACK ONLY) FOR INTERVAL 50 MSEC BELOW

Probabilistically derived oil and gas in-place volumes for Oyo Deep, Upper Miocene reservoir are presented in Table 4.5, with estimated GCoS. Prospective Resources are presented in Tables 0.4 and 0.5.


42

TABLE 4.5

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES OYO DEEP

Prospect Name

Licence Name



Oyo Deep OML 120 1 5 11 6 0 1 5 2 35

4.12.3 Other Potential

Correlation of the reservoirs from Oyo West to Oyo Central suggest that there may be additional potential for reservoir development to the south of the Oyo Central wells, at a younger stratigraphic level than the main Oyo Central reservoirs (Figure 4.14). This prospective interval could have either a structural and/or stratigraphic closure but has not been penetrated by any of the previous wells and this concept has not been fully evaluated at this time. No prospective volumes have been assigned at this time, but further insight into this seismic package could be obtained once Oyo-8 is drilled in 2014.

FIGURE 4.14

RMS AMPLITUDES FOR UNIT 3/4 AT OYO WEST EXTRAPOLATED INTO OYO CENTRAL AREA, SUPERIMPOSED ON DEPTH STRUCTURE TOP T1A RESERVOIR


43

5. OTHER DISCOVERIES 5.1 Ebolibo-1 The Ebolibo-1 well was drilled in 2007, in the far south east of OML 121 (Figure 3.1). Ebolibo was a seismically defined, faulted 4-way dip closed structure associated with a large down to the west normal fault. The discovery is supported by amplitudes, which shut-off down-dip approximately in coincidence with structure contours (Figure 5.1). The Ebolibo-1 well encountered nearly 30 m of gas in the Pleistocene section, at the A098 and A102 intervals. However the discovery was considered sub-economic and the well was plugged and abandoned. GCA understands that CAMAC currently has no plans to develop the discovery. GCA considers the resources encountered at the Ebolibo discovery as Contingent Resources. In order to derive a range of resource volumes, GCA has reviewed the mapping conducted by CAMAC over the discovery. It appears that two gas bearing reservoir intervals were mapped and encountered by the well; both are Pleistocene in age (A098 and A102). Both of the mapped intervals have strong amplitude responses associated with them, which are assumed to be associated with a (soft) gas seismic response. The areal extent of the amplitude response at the upper (A098) reservoir interval is 18.4 km2 within OML 121 and from examination of log data appears to have a pay thickness of approximately 9 m. The areal extent of the amplitude response at the lower (A102) reservoir interval is 3.3 km2 and log data indicates a hydrocarbon pay zone of 26 m. The combined pay zone thickness of the upper and lower reservoir intervals is 35 m, which approximately agrees with published reports. A low (P90) case for calculating GRV has been defined using CAMAC’s interpreted surfaces and GCA’s polygon outlines, incorporating both reservoir intervals. The GRV used in the volumetric estimations at the low case was derived by using a fraction of the best case GRV, which represents a reasonable uncertainty in the mapping, depth conversion and percentage of hydrocarbon fill in the structure. A best (P50) case for calculating GRV has been defined using CAMAC’s interpreted surfaces and GCA’s polygon outlines, incorporating both reservoir intervals. The GRV used in the volumetric estimations at the best case was derived by using a pay zone thickness of 35 m distributed between the two reservoir intervals (as described above). A high (P10) case for calculating GRV has been defined using CAMAC’s interpreted surfaces and GCA’s polygon outlines, incorporating both reservoir intervals. The GRV used in the volumetric estimations at the high case was derived by using a multiplier of the best case GRV, which represents a reasonable uncertainty in the mapping, depth conversion and percentage of hydrocarbon fill in the structure. Oil and gas in place volumes are presented in Table 5.1 and gas Contingent Resources are presented in Table 5.2.


44

TABLE 5.1

SUMMARY OF CONTINGENT OIL AND GAS IN PLACE VOLUMES EBOLIBO

Prospect Name

Licence Name

Gross Unrisked In Place Volumes (MMBbl) (Bscf)

Low Best High Mean Low Best High Mean Ebolibo OML 121 0 0 0 0 122 202 309 210

TABLE 5.2

SUMMARY OF GROSS AND NET GAS CONTINGENT RESOURCES

EBOLIBO AS AT 30th JUNE, 2013

Asset Name

Licence Name

Gross Contingent Resources (Bscf)

Working Interest

(%)

Net Contingent Resources (Bscf)

1C 2C 3C Mean 1C 2C 3C Mean

Ebolibo OML 121 71 120 188 126 30 21 36 57 38

Notes: 1. The meaningful Contingent Resource volume reported here is the 2C, or ‘Best Estimate’ value. 2. No economic limit cut off is applied for Contingent Resources. 3. The volumes reported here are “Unrisked” in the sense that “Chance of Development” values have

not been arithmetically applied to the designated volumes within this assessment. “Chance of Development” represents an indicative estimate of the probability that the Contingent Resource will be developed, which would warrant the reclassification of that volume as a Reserve.

4. Working interest shown assumes CAMAC would opt to invest in any future investment under the Production Sharing Contract with Allied.


45

FIGURE 5.1

VERTICAL SEISMIC SECTION THROUGH EBOLIBO DISCOVERY WITH DEPTH CONTOURED MAXIMUM AMPLITUDE MAP ON A098

PLEISTOCENE HORIZON


46

6. PROSPECTIVE RESOURCES OML 120 and 121 CAMAC has conducted a work programme of interpretation and mapping to define potential prospects and leads in OML 120 and 121 (Figure 6.1). GCA has reviewed all of the potential drilling targets and provides an independent assessment of the geological description and definition of all prospects and leads, the prospective resources and the geological risk.

FIGURE 6.1

CAMAC PROSPECT AND LEAD PORTFOLIO OML 120 AND 121

OML boundary

Ewo 3D seismic survey

Oyo 3D seismic survey

“New” OML 120-121 seismic survey

Field/DiscoveryWestern OML 120: Miocene Prospects (oil & gas)Western OML 120 & 121: Pliocene Prospects (oil & gas)Eastern OML 121: Pliocene to Pleistocene Prospects (gas)OML 120: Miocene Leads (oil & gas)Eastern OML 121: Pliocene to Pleistocene Leads (oil & gas)OML 121: Miocene Lead (gas)Solid Outline = ProspectDashed Outline = Lead

Erha Field(Exxon)

Ewo North (UT & DT)Prospects

Ewo Deep

Prospect O

Prospect G

A (East & West)

D

Prospect Q

Oyo WestOyo T1B & Oyo Deep

C

ErengProspect

Prospect P

Songu

R

M

Kigbo Prospect

Eba

Onigu

Kigbo Deep

Ereng B

10 km

Oyo Field(CAMAC)

EboliboDiscovery

OML 120

OML 121


47

Prospective Resources are assigned to ten prospects (Tables 6.1 and 6.2) distributed over OML 120 and 121 in a series of combination structural-stratigraphic traps in reservoirs of Miocene to Pliocene age.

TABLE 6.1

SUMMARY OF GROSS UNRISKED PROSPECTIVE RESOURCES (PROSPECTS) NIGERIA AS AT 30th JUNE, 2013

Prospect Name

Licence Name

Gross Unrisked Prospective Resources GCoS


P OML 121 11 41 96 48 191 427 805 470 56 G OML 120 39 64 181 118 17 24 33 24 56 Oyo T1B OML 121 1 2 4 2 1 3 7 3 64 Oyo Deep OML 120 0 1 3 2 0 1 3 1 35 Oyo Ereng OML 120 42 78 134 85 27 90 196 103 13 Ewo North UT OML 120 3 17 104 46 4 29 204 92 22 Ewo North DT OML 120 1 3 10 4 12 42 99 51 32 O OML 120 1 2 5 3 30 64 112 68 63 Kigbo OML 121 0 0 0 0 90 226 424 245 42 Q OML 120 54 96 156 102 31 86 175 97 17 Notes: 1. Prospects are features that have been sufficiently well defined, on the basis of geological and

geophysical data, to the point that they are considered viable drilling targets. 2. “Gross Unrisked Prospective Resources” are 100% of the volumes estimated to be recoverable from

the field. 3. The GCoS reported here represents an indicative estimate of the probability that drilling this




48

TABLE 6.2

SUMMARY OF NET COMPANY UNRISKED PROSPECTIVE RESOURCES (PROSPECTS) NIGERIA AS AT 30th JUNE, 2013

Prospect Name

Licence Name

Working Interest

(%)

Net Unrisked Prospective Resources GCoS


P OML 121 30 3 12 29 14 57 128 241 141 56 G OML 120 30 12 19 54 36 5 7 10 7 56 Oyo T1B OML 120 30 0 1 1 1 0 1 2 1 64 Oyo Deep OML 120 30 0 0 1 0 0 0 1 0 35 Oyo Ereng OML 120 30 13 23 40 25 8 27 59 31 13 Ewo North UT OML 120 30 1 5 31 14 1 9 61 28 22 Ewo North DT OML 120 30 0 1 3 1 4 13 30 15 32 O OML 120 30 0 1 2 1 9 19 34 20 63 Kigbo OML 121 30 0 0 0 0 27 68 127 73 42 Q OML 120 30 16 29 47 31 9 26 53 29 17


geophysical data, to the point that they are considered viable drilling targets. 2. The GCoS reported here represents an indicative estimate of the probability that drilling this



4. Working interest shown assumes CAMAC opts to invest in each asset at its full working interest within the guidelines of the Production Sharing Contract with Allied.

Prospects are defined by structural mapping from three 3-D seismic surveys: Ewo 3-D, acquired 1994, Oyo 3-D, acquired 1994, “New” 120,121 3-D survey, acquired 2008-2009 (Section 3). All data have been reprocessed and various seismic attributes and derivative data volumes have been used to infer the presence of potential reservoirs and of direct indications of the presence of hydrocarbons. The deeper pool potential beneath the T1A reservoir in Oyo Central Field, the T1B and Oyo Deep prospects are discussed in detail in section 4.12 of this report. Other volumetric parameters are estimated with respect to regional analogues and the analyses conducted on other wells on OML 120 and 121, (wells Oyo-1 to Oyo -6, Ewo-1 and Ebolibo-1). In particular, a regional model of the variation of key parameters with depth has been derived including porosity, reservoir pressure and temperature; hence the Formation Volume Factor (Bo) and Gas Expansion Factor (Bg). These allow estimates to be made of appropriate values to be made for each prospect. A Geological Chance of Success (GCoS) for each prospect or lead has been estimated using GCA’s own internal system. This addresses four individual component probabilities


49

for the presence of reservoir, source, trap/seal and petroleum system timing to derive a net probability for each prospect or lead. These are reported in Tables 6.1, 6.2 and 6.3 summarising prospective resources. Note that all prospective resource volumes are reported on an unrisked basis. Prospects and Leads have been divided by GCA into groups as follows: • Section 6.1 - OML 120: Miocene prospects (oil and gas)

o Prospect G o Prospect Ereng o Prospect Ewo North UT o Prospect Ewo North DT o Prospect Q

• Section 6.2 - OML 120 and 121: Pliocene prospects (oil and gas) o Prospect O o Prospect P

• Section 6.3 - Eastern OML 121: Pliocene to Pleistocene Prospects (gas) o Prospect Kigbo

• Section 6.4 - OML 120: Miocene Leads (oil and gas)

o Ereng B o Ewo Deep o Lead A o Lead C o Lead D

• Section 6.5 - Eastern OML 121: Pliocene to Pleistocene Leads (gas)

o Lead R o Onigu o Eba o Songu o Lead M

• Section 6.6 – OML 121: Miocene Leads o Kigbo Deep

Assessment of the hydrocarbon phase in each prospect takes into account the regional models of hydrocarbon generation described above and also the local seismic signature, in particular the recognition of anomalously high amplitudes and polarity changes, inferred as indicating gas presence, stepped decline in amplitudes with depth that imply the presence of multiphase hydrocarbon fluid presence, and cross-cutting or flat events, indicating possible fluid (gas-water, or gas-oil) contacts. It is noted that the character of some of the deeper prospects is ambiguous and hydrocarbon charge may be of gas, through migration from thermally mature kitchen areas. Alternatively, a liquid phase may be encountered where elevated formation pressures may maintain the formation above the fluid bubble point, and/or seal competence may not be sufficient to retain a gas column. This uncertainty is reflected in the volumetric analysis conducted by GCA. Details of individual targets are discussed below, following the groups described above.


50

6.1 Western OML 120 Miocene Prospects (Oil and Gas) 6.1.1 Prospect G

Prospect G is located at the western margin of OML 120. It is 10 km east of the Erha field, in OML 135, a giant field reportedly containing a recoverable resource of 500 MMBbl and 3.2 Tcf gas. Prospect G lies in approximately 800 m of water. The prospect extends beyond the OML 120 Block boundary to the west, but all comments and volumes calculated herein pertain only to that area of the prospect that lies within OML 120. Reservoirs are inferred to be of Upper Miocene (Tortonian to Messinian) age. It is GCA’s understanding that Prospect G is likely to be included in the drilling schedule in 2014 alongside the development drilling and completion of Oyo Central field wells. No formal well proposal has yet been presented to GCA.

Controls on sand distribution are complex and sandstone bodies consist of a stacked series of submarine fans and channels, localised partly by the sea floor topography created by early shale diapir movement, as have been inferred from published data on the Erha Field. Regional mapping of likely sand distribution suggests that Prospect G lies on a southern branch from the major sand feeder system that fed the Erha area. The trap is structural and is created by rollover on the crest of a shale diapir in the hangingwall of an array of listric faults which sole out into the heart of the shale ridge. Trap formation was mainly in the Pliocene to Pleistocene, with some minor movement of the larger faults, bounding the fault array, continuing until the present day. Regional seismic interpretation suggests that the reservoirs lie above and below the “H300” marker, within the Middle Miocene. There is a strong amplitude signature at the level of the Main Sand, but it is noted that this occupies different structural levels in different fault blocks, suggesting structural compartmentalisation of the prospect (Figure 6.2).


51

FIGURE 6.2

VERTICAL SEISMIC SECTION THROUGH PROSPECT G WITH DEPTH CONTOURED MAXIMUM AMPLITUDE MAP

The prospect contains the possibility of stacked reservoir units, and there is evidence of a common hydrocarbon contact in the fault blocks that comprise the east of the prospect, but of individual stacked hydrocarbon pools elsewhere. For the purposes of calculating the gross rock volume within OML 120, GCA has generated a Petrel Model which was based on the stratigraphy encountered at the Erha-1 well (Figure 6.3). Within the model, one grid was generated to represent each of the Low, Best and High cases. Volumes within the model are bound to the west by the OML 120 block boundary (it is recognised that the western edge of

Ewo Horizon

N S

0 0.75 1.5 km

0 1 km

Ewo Horizon Lower

Northern Fault Segment

Southern Fault Segment

S

N

Western Limit of OML -120


52

the trap may extend into a neighbouring licence). To the East the model is limited by a verticalised fault, which is considered to be associated with the main south west to north east trending listric fault (Figure 6.4). The model was split into two segments to account for the apparent difference in fluid contacts observed on amplitude extractions from the seismic cube.

FIGURE 6.3

STRATIGRAPHIC SECTION APPLIED TO PROSPECT G PETREL MODEL


53

The low case (P90) ascribes potential to the top three sands (1-3) in the Petrel model (Figures 6.3 and 6.4), which represents 77 m of gross sand interval. Structural contours show a potential spill point for the structure to the South East (Figure 6.2). The OWC for the low case was set 10 m below the structural spill in the southern segment and 70 m below the structural spill point in the northern fault segment. This corresponds to strong amplitude shut-offs on amplitude extraction data. The 3D seismic volume covering Prospect G shows the brightest amplitudes to be present within this package. The amplitude response observed at the top of the ‘main sand’ package may be indicative of gas phase hydrocarbons. This package on the seismic data corresponds to sands 2 and 3 within the Petrel model. To accommodate the likelihood of gas phase hydrocarbons being present at these intervals at Prospect G the Petrel model includes mixed phase hydrocarbons at sands 2 and 3, through the use of GOC and OWCs. Sand 1 is considered as purely oil phase hydrocarbons.

FIGURE 6.4

3D VIEW TO WEST OF PROSPECT G PETREL MODEL .

The best case (P50) ascribes potential to the top four sands (1-4) in the Petrel model (Figures 6.3 and 6.4), which represents 91 m of gross sand interval. Structural contours show a potential spill point for the structure to the South East (Figure 6.4). The fluid contacts for the best case were set to the same as those used in the low case (above). Sands 1 and 4 are considered as oil phase only and sands 2 and 3 are considered as mixed phase. The high case (P10) ascribes potential to six sands (1-6) in the Petrel model (Figures 6.3 and 6.4), which represents 158 m of gross sand interval. Structural contours show a potential spill point for the structure to the South East (Figure 6.4). The OWC for the high case was set 70 m below the structural spill in the


54

southern segment and 190 m below the structural spill point in the northern fault segment. This corresponds to weak amplitude shut-offs on amplitude extraction data. Sands 1 and 4-6 are considered as oil phase only and sands 2 and 3 are considered as mixed phase. Reservoir properties have been defined with respect to the data available on the Oyo and Erha fields, adjusted where necessary for depth. Oil and gas properties from regional data, along with estimates of the ambient reservoir conditions of temperature and pressure are used to derive the required Bo and Bg values. Liquid hydrocarbons are expected to be oil. An allowance has been included for condensate content within the gas volume. In Place Volumetric estimates are presented in Table 6.3.

TABLE 6.3

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES PROSPECT G

Prospect Name

Licence Name



G OML 120 159 225 660 425 29 40 53 41 56

6.1.2 Prospect Ereng

Prospect Ereng straddles the boundary between OML 120 and 121. It is a deep and complex trap in sandstones interpreted of Middle Miocene (Serravalian) to possible Lower Miocene age. It lies in approximately 690 m water depth. There are two sandstone intervals which are included in this analysis; Ereng, within the interval designated as the H470-H500 sequence and Ereng B, within that designated the H538-H562 sequence. Both show a strong amplitude signature, interpreted as representing the presence of multi-storey, stacked submarine channel sand bodies, but potential trap geometries are clearer in the Ereng interval. At this stage, although indications exist of individual channel cutoffs, possibly controlling seismic amplitude, and hence sealing geometry and hydrocarbon fill, no clear trap can be defined in the Ereng B interval and it is designated as a lead. The Ereng trap is created within an overall structural low within an incised amalgamated submarine channel body oriented approximately E-W. A transverse section clearly shows the overall channel geometry (Figure 6.5). Critical to trap formation are the lateral and bottom seals against sediments equivalent to the channel sandstones and into which the channel has incised.


55

FIGURE 6.5

VERTICAL SEISMIC SECTION (NNW-SSE) THROUGH ERENG A PROSPECT AND ERENG B LEAD

Northwards the closure is created by the channel margin and southwards onto structural highs created by two overlapping, en echelon mud diapir trends. Structural growth is partly syn-depositional to the southeast, against which the channel thins, and partly post-depositional to the southwest where a major faulted mud ridge appears to truncate the reservoir sands (Figure 6.6).

FIGURE 6.6

VERTICAL SEISMIC SECTION (ENE-WSW) THROUGH ERENG A PROSPECT AND ERENG B LEAD

The low volume case (P90) for the Ereng prospect is defined by the lowest position of the incised channel margin on the northern flank of the channel which


56

creates the most robust view of the stratigraphic component of the trap. This would permit a closing contour at approximately 3,300 m on the top surface of the reservoir. The best case (P50) volume is taken at the point above which the highest amplitudes occur (Figure 6.7), tentatively equated to the best quality sandstones near the top of the reservoir zone with a possibility of hydrocarbon fill. It would indicate the base of the trap at approximately 3,420 m.

FIGURE 6.7

CONTOURED DEPTH STRUCTURE TOP ERENG A SAND AND RMS AMPLITUDES FOR ERENG A INTERVAL

The upside high (P10) case encompasses the entire amplitude anomaly characterising the trap. This would extend the base of the trap down to circa 3,540 m in the axis of the channel, approximately at the level of the lowest synclinal spill point. There is no particular evidence for gas content of the Ereng Prospect, and fluid content is uncertain.


57

In all cases, the key uncertainty centres on the nature of the combination of stratigraphic pinchout, channel margin truncation and structural closure against the faulted shale ridge to provide the key elements of the trap. In Place Volumetric estimates are presented in Table 6.4.

TABLE 6.4

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES PROSPECT ERENG

Prospect Name

Licence Name



Ereng OML 120 133 228 364 240 47 150 321 171 13

6.1.3 Prospect Ewo North Upthrown (UT)

This is one of a cluster of prospects/leads on the northern edge of the seismic survey area in approximately 750 m of water. It lies 5 km NNW of the Ewo-1 well and targets the same fault block, although in a deeper reservoir level not penetrated by the previous well, and further to the north west beneath the shallow dipping listric fault plane (Figure 6.8). Ewo-1 did not reach its target depth but encountered a minor (7.5 m) zone containing untested oil shows at the top of the Miocene section. The reservoir target at Ewo North UT is estimated to be 1,290 m below the oil-bearing sandstones in Ewo-1. Reservoirs are Middle Miocene (Serravalian) age.

FIGURE 6.8

VERTICAL SEISMIC SECTION THROUGH EWO NORTH UPTHROWN (UT)


58

The boundaries of the prospect to the north are not well constrained by the 3D reprocessed data volume, but it can be seen to comprise an interval of high amplitudes in the footwall of a low angle listric fault plane that dips north-westward. Deep imaging of this fault is uncertain; it may have been modified by deep seated shale diapirism. Two potential sand intervals are recognised, the upper designated Horizon 1 and the lower Horizon 2 (Figure 6.8). Horizon 1 is best defined and can be seen to comprise an incised channel complex, interpreted to be filled with multi-storey, stacked channel sand bodies, although the northern margin of the sand body is obscure and it is not entirely clear whether the trap is created by fault closure or by the margin of the channel body. Horizon 2 does not contain any definable sandstone geometries. In the low volumetric case (P90), the prospect is limited to two separate pools in each of Horizon 1 and Horizon 2, essentially occupying the crestal location against the western bounding fault. There is strong amplitude support for this case in the Lower sand (Figure 6.9).

FIGURE 6.9

CONTOURED DEPTH STRUCTURE TOP EWO NORTH UT HORIZON 1 AND RMS

AMPLITUDES FOR HORIZON 1 INTERVAL


59

Consideration of a wider amplitude signature suggests that the two sands may be in communication in the best case (P50). Trap closure would rely on amplitude shut-off at the margin of the channel body, although the closure northwards may also be in part at the bounding fault. Uncertainty over the nature of the northern channel margin in Horizon 1 leads to the possible definition of a high (P10) case incorporating a larger volume. This would necessarily be bounded to the south by the channel margin, and there is some amplitude support for this, particularly in the far stack volume. Within Horizon 2 (Figure 6.10), reservoir quality away from the crest of the structure would appear to be poor. The prospect at this level would be bounded to the south by the limit of the sandstones. To the north, sand distribution is obscure, but the prospect has been tentatively extended to the bounding fault.

FIGURE 6.10

CONTOURED DEPTH STRUCTURE TOP EWO NORTH UT HORIZON 2 AND RMS

AMPLITUDES FOR HORIZON 2 INTERVAL


60

There is additional unmapped potential in the lowermost (Horizon 3) layer approximately 2.5 km to the southeast of the Ewo North UT prospect. In Place Volumetric estimates are presented in Table 6.5.

TABLE 6.5

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES PROSPECT EWO NORTH UT

Prospect Name

Licence Name



Ewo North UT OML 120 8 50 298 132 6 49 350 155 22

6.1.4 Prospect Ewo North Downthrown (DT)

The downthrown prospect at Ewo North lies in approximately the same location as the Ewo North Upthrown prospect (Section 6.1.3), but at a shallower structural level in the hangingwall of the same controlling fault. It is approximately 5 to 7.5 km northwest of the Ewo-1 well, in approximately 750 m water depth. Sandstones are of Upper Miocene age, in the intervals designated Sequences 235 and 245 which are stratigraphically younger than the interval penetrated by Ewo-1 in which a minor oil occurrence was noted. Four reservoir levels can be identified with potential hydrocarbons occurring in combination structural and stratigraphic traps. In the lower three (sequence 245) the potential lies in the dip closure formed by the fault rollover (Figure 6.11), but in the uppermost interval (sequence 235), the potential is offset to the north, within a major ENE-WSW oriented channel sand body. It would only therefore be possible to test all four closures within their overlap. Because of their similar overall geology, they are evaluated together, although the pools might more properly categorised as comprising two separate prospect locations. In each case individual channel systems can be recognised, in contrast to the stacked and amalgamated sand bodies that characterise other prospects.


61

FIGURE 6.11

VERTICAL SEISMIC SECTION THROUGH EWO NORTH DOWNTHROWN (DT) PROSPECT

Definition of the northern edge of the horizon 235 sandstone body is impeded by lack of seismic definition near the edge of the survey, but a clear channel margin can be recognised to the south. It is not clear whether the northern margin of the trap is provided by the equivalent channel margin or by closure against a fault system (Figure 6.12). The low case (P90) volume is defined by a small dip-closed body (to the north and east) within the channel, whose margin provides the seal to the south. The best case (P50) extends potential down to include the most significant amplitudes. It is noted that similar amplitudes characterise a small area within the dip-closed prospect to the east (Figure 6.12), suggesting that these represent a hydrocarbon-filled reservoir unit. The high case (P10) includes the entire channel sand body.


62

FIGURE 6.12

CONTOURED DEPTH STRUCTURE TOP EWO NORTH DT HORIZON 235 AND RMS AMPLITUDES FOR HORIZON 235 TO 245 INTERVAL

The trap at the 245, Mid Sandstone and Lower Sandstone levels is created by rollover in the hangingwall of a major extensional fault. Each appears to constitute a separately sealed pool in a sequence where sand development is relatively sparse. Principal reservoir development is controlled by submarine channel configuration, but the three pools appear to have a component of larger dip closure, controlled by the rollover into the master fault (see Figure 6.13 for an example at the Mid Sandstone level).


63

FIGURE 6.13

CONTOURED DEPTH STRUCTURE TOP EWO NORTH DT MID SANDSTONE HORIZON 1 AND RMS AMPLITUDES FOR MID SANDSTONE TO LOWER

SANDSTONE INTERVAL

The strong amplitude signature of the sands suggests a predominant gas charge but the possibility of oil legs has been incorporated into the volumetric analysis. Although the presence of sand containing gas is strongly implied by the seismic response in the core of each prospect, the key uncertainty would appear to be the extent of reservoir quality sandstones and the potential for liquid hydrocarbons. In Place Volumetric estimates are presented in Table 6.6.

TABLE 6.6

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES

PROSPECT EWO NORTH DT

Prospect Name

Licence Name



Ewo North DT OML 120 2 12 35 16 21 72 163 84 32


64

6.1.5 Prospect Q

Prospect Q is a structural trap comprised of a faulted 4-way dip closed structure, located 6.5 km to the south west of the Oyo field. Prospect Q is located in approximately 420 m of water. CAMAC has interpreted prospective intervals at three separate levels in the Middle to Late Miocene, and two intervals in the Pliocene to Pleistocene, each prospective interval has been mapped on the 3D dataset (Oyo seismic cube). The three prospective intervals in the Middle to Late Miocene all require stratigraphic pinch-out on to shale diapirs and various faults to seal in order for the trap to work. Mapping the location of the pinch-out of the various Miocene intervals onto the flanks of the diapirs is difficult, which makes the trap difficult to define precisely. The seismic character of the Miocene section is generally low amplitude. Intervals of higher amplitude reflections, with some internal geometry indicative of more sandy facies, can be observed below the Miocene seismic surfaces picked by CAMAC (Figure 6.14). The brightest amplitudes are associated with the Miocene horizon 3, however these amplitude limits ado not follow structure contours hence are less likely to be a direct hydrocarbon indicator. The two shallower surfaces interpreted by CAMAC, do form a faulted 4-way dip closed structure. The faulting is complicated and composed of multiple phases of fault movement, faults are well imaged well set and it is possible to see that certain fault traces continue to the seafloor, which indicates that some faults may still be active today. The seismic character of the shallower horizons is indicative of a more sand prone facies. Subtle amplitude brightening can be observed into some of the faults. CAMAC’s interpreted surface ‘Oyo Horizon one’ is at the same stratigraphic interval as the intervals that are productive at Oyo West. A low (P90) case for calculating GRV has been defined using CAMAC’s interpreted surfaces and polygon outlines, incorporating all five prospective intervals (three Miocene and two Pliocene). The GRV used in the volumetric estimations at the low case was derived by using a fraction of the best case GRV, which represents a reasonable uncertainty in the mapping, depth conversion and percentage of hydrocarbon fill in the structure. A best (P50) case for calculating GRV has been defined using CAMAC’s interpreted surfaces and polygonal outlines, incorporating all five prospective intervals (three Miocene and two Pliocene). The structural spill point of each surface was applied as the cut-off for hydrocarbon column height. GRV was calculated within CAMAC’s polygon outlines, using the seismically derived top depth surface. This assumes the structure at each interval is ‘fill-to-spill’. The reservoir thickness of the Miocene intervals was restricted to 75 m. A high (P10) case for calculating GRV has been defined using CAMAC’s interpreted surfaces and polygon outlines, incorporating all five prospective intervals (three Miocene and two Pliocene). The GRV used in the volumetric estimations at the high case was derived by using a multiplier of the best case GRV, which represents a reasonable uncertainty in the mapping, depth conversion and percentage of hydrocarbon fill in the structure. Oil and gas in place and the GCoS are presented in Table 6.7.


65

TABLE 6.7

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES PROSPECT Q

Prospect Name

Licence Name



Q OML 120 219 350 533 366 53 146 290 162 17

CAMAC proposes an extension of Prospect Q to the west of its current location at the Miocene Horizon 2 interval, which would add an additional 4,152 acres to the prospect. GCA considers that mapping an extension to the west is compromised by the poor quality of the Ewo 3D seismic volume in this area and would benefit from reprocessing, using modern techniques. The 2D seismic grid in this area is contaminated with multiples and other seismic artefact that may obscure seismic interpretation at certain key intervals. Thus GCA has excluded this area from its assessment of Prospect Q volumes.


66

FIGURE 6.14

VERTICAL SEISMIC SECTION THROUGH PROSPECT Q WITH CONTOURED DEPTH MAP ON SHALLOW HORIZON


67

6.2 Western OML 120 and 121: Pliocene Prospects (Oil and Gas) 6.2.1 Prospect O

Prospect O lies in the extreme west of OML 120, partly straddling the boundary with OML 133. The evaluation and volumetric analysis reported here address only that part of the prospect which lies in OML 120. Water depth is approximately 860 m. The prospect lies in the same Lower Pliocene canyon-fill section as that which forms the reservoirs at Oyo West and Oyo Central, with reservoirs expected to be composed of similar amalgamated stacked channel sandstones (Figure 6.15).

FIGURE 6.15

VERTICAL SEISMIC SECTION THROUGH PROSPECT O

The entire stacked channel fill sequence is characterised by strong amplitudes, in contrast to the mud-dominated background sediment into which the canyon incised. At the top of the prospect are particularly bright events, interpreted as indicating the presence of gas-filled sandstone. There are two of these areas that stand out. One is the crest of the prospect, the other on a terrace located on the flank. Both of them lie within the overall structural closure (Figure 6.16). In the low case (P90), the prospect is restricted to the crestal part of the structure and the lower anomaly is inferred as a thin gas column within a dip closure, but of no volumetric significance. The best case (P50) enlarges the gas column to include this lower anomaly. The high case (P10) includes all of the channel body down to the level of the maximum spill point. In all cases the bulk of the stacked channel sands lie below the level of the structural closure/hydrocarbon water contact and are interpreted as having no viable lateral or bottom seal.


68

FIGURE 6.16

CONTOURED DEPTH STRUCTURE TOP O PROSPECT RESERVOIR AND RMS AMPLITUDES FOR INTERVAL BELOW H50 REGIONAL MARKER INCLUDING OYO

CANYON TREND

The prospect is characterised by extremely bright amplitudes which can be shown to lie within the structural closure, indicating primarily gas potential. Presence of oil is suggested by its position with respect to the regional kitchens and a thin oil leg is incorporated into the volumetric analysis. Oil and gas in place and the GCoS are presented in Table 6.8.

TABLE 6.8

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES PROSPECT O

Prospect Name

Licence Name



O OML 120 3 9 19 10 51 107 185 114 63


69

6.2.2 Prospect P

Prospect P lies in the extreme southwest of OML 121 in approximately 780 m of water. It is a complex trap relying on closure created in Lower Pliocene canyon-fill sandstones, partly via southward pinchout of the canyon-fill sandstone body onto a structural high overlying a shale ridge, and partly by fault closure to the northeast as a result of collapse of the underlying shale diapir (Figure 6.17). Latest motion on the closing fault is of Pleistocene age, but unlike many other fault planes in the area, does not continue to the Recent, which may be a critical factor in maintaining a viable fault seal. Regional correlation of the seismically-defined stratigraphic units suggests that the canyon at Prospect P is approximately the same Lower Pliocene age as that which contains the productive reservoirs at Oyo Central and Oyo West (Figure 6.17) and the reservoir is interpreted as a multi-storey stacked deep water turbidite channel complex. Precise distribution of reservoir sandstones within the prospect is uncertain. The location is remote from nearby well data to closely calibrate the depth conversion but it is estimated that the crest of the prospect lies at approximately 1,400 m below sea level. The prospect is characterised by an extremely high amplitude response (Figure 6.18) with an approximately flat base, and a cross-cutting flat spot that appears to strongly indicate the presence of a gas column and associated gas-liquid contact (Figure 6.19). Based on regional hydrocarbon source rock and maturity models, it is thought likely that the area of Prospect P has been exposed to a hydrocarbon charge containing both gas and oil.

FIGURE 6.17

VERTICAL SEISMIC SECTION THROUGH PROSPECT P


70

FIGURE 6.18

RMS AMPLITUDES FOR BROAD INTERVAL 0.4 SECS BELOW H50 UPPER PLIOCENE REGIONAL MARKER


71

FIGURE 6.19

CONTOURED DEPTH STRUCTURE TOP PROSPECT P RESERVOIR AND RMS AMPLITUDES FOR BULK INTERVAL BETWEEN TOP AND BASE RESERVOIR

Based on a comparison with the response at the Oyo field, taking into account the differences in the polarity of the seismic data between the two surveys, it is inferred that there is some evidence for a deeper fluid contact than the more obvious flat spot referred to above (Figures 6.20 and 6.21). At this stage, the precise nature of this cannot be confirmed without further modelling, as it is not consistently observed throughout the prospect in all sedimentary facies, and furthermore it may represent a residual or palaeo-fluid contact. Nonetheless, it suggests the presence of oil and indicates the possibility of a substantial oil column that has been incorporated into the upside volumetric scenario.

High case

Low case

Best case

SE

NW

Figure 7.20

0 1 2 km


72

FIGURE 6.20

VERTICAL SEISMIC SECTION (ARBITRARY LINE) THROUGH PROSPECT P

FIGURE 6.21

CONTOURED TIME STRUCTURE MAP AND RMS AMPLITUDES FOR INTERVAL 0.075 SECS BELOW TOP OF P PROSPECT RESERVOIR


73

A low case (P90) is defined by the extent of the amplitude anomaly and by the upper limit of the main flat spot, but excluding units at the crest of the prospect that do not have the strong amplitude response associated with gas-charged sandstones. This case is characterised by a bulk rock volume gas/oil ratio of 0.95, i.e. it is viewed that the amplitude response is essentially solely due to a gas charge. The most likely (P50) case includes the possibility of the development of a significant oil leg (see above) beneath the more clearly imaged gas column, based on the interpretation of the seismic amplitude signature. The high (P10) case for the volume of the prospect is defined by including the volume of the prospect down to the level of the maximum spill point from the depth structure map on the top reservoir surface. More muted seismic amplitudes suggest that this additional volume, if it is part of the trap, is more likely filled by oil rather than gas. The overall seismic signature of the prospect is similar to that at Oyo and a similar range of reservoir parameters (net/gross and net porosity) have been used, along with estimates of oil and gas saturation. Oil and gas properties from regional data, along with estimates of the ambient reservoir conditions of temperature and pressure are used to derive the required Bo and Bg values. Liquid hydrocarbons are expected to be oils, approximately 35° API. An allowance has been included for a condensate content within the gas volume. Data from Oyo suggest a relatively lean wet gas with a condensate/gas ratio (CGR) of between 8-12 Bbl/ MMscf of a liquid whose gravity ranges from 48.8-50.4° API, but regional data suggest that this can be higher: a small upside has been incorporated into the volumetric analysis. Oil and gas in place and the GCoS are presented in Table 6.9.

TABLE 6.9

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES

PROSPECT P

Prospect Name

Licence Name



P OML 121 39 151 336 173 325 719 1319 782 56 6.3 Eastern OML 121: Pliocene to Pleistocene Prospects (Gas) 6.3.1 Prospect Kigbo

The Kigbo Prospect is located towards the south east of OML 121 and lies in approximately 400 m of water depth, 10 km west of the Ebolibo-1 gas discovery well. The Ebolibo-1 Well was drilled in 2007 on a seismically defined, faulted 4-way dip closed structure. The discovery is supported by amplitudes, which shut-off down-dip in coincidence with structure contours. The Ebolibo-1 well encountered nearly 30 m of gas in the Pleistocene section.


74

CAMAC has defined the Kigbo Prospect at the H114 and H114 A (Plio/Pleistocene) seismic intervals (Figure 6.22).

FIGURE 6.22

VERTICAL SEISMIC SECTION THROUGH KIGBO WITH DEPTH CONTOURED MAXIMUM AMPLITUDE OF H114


75

Both of the prospective intervals are supported by amplitude brightening up-dip towards antithetic faults The antithetic faults are associated with a large down to the south normal fault. The down-dip amplitude shut-off of the H114 interval is coincident with structure contours (Figure 6.23). The amplitude response of the H114 A interval is not as extensive or as high amplitude as the H114 interval. The seismic response and character observed at Kigbo is very similar to that observed at the Ebolibo discovery, which is represented by a strong trough-peak-trough response and thought to be indicative of the presence of gas phase hydrocarbons.

FIGURE 6.23

CONTOURED MAXIMUM AMPLITUDE MAPS – KIGBO H114 AND H114 A


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Analysis of thermal maturity modelling results, indicate that the Kigbo Prospect is located in an area prone to charge with gas-phase hydrocarbons. GCA agrees with CAMAC that it is less likely that the Kigbo location has received any oil-phase hydrocarbons, which is supported by analysis of seismic data. The gross rock volume at the low case for Kigbo, is defined with a polygon constructed around the amplitude response at the H114 interval (Figure 6.23). A constant gross thickness of 30 m was applied to the low case, which represents an approximate thickness of a single seismic loop (approximately 30 msecs). The gross rock volume at the best case for Kigbo, used the same polygon as used for the low case described above. The area for the best case also includes a polygon constructed around the seismic amplitude observed at the slightly deeper H114 A seismic interval. A constant gross thickness of 50 m was applied to the best case. A high case for the Kigbo Prospect is defined using the combined amplitude areas from the H114 and H114 A seismic intervals (as was applied in the best case). A gross thickness of 70 m was applied to the combined area in order to derive a gross rock volume for the high case. Oil and gas in place and the GCoS are presented in Table 6.10.

TABLE 6.10

SUMMARY OF PROSPECTIVE OIL AND GAS IN PLACE VOLUMES PROSPECT KIGBO

Prospect Name

Licence Name



Kigbo OML 121 0 0 0 0 154 382 693 407 42

6.4 Western OML 120: Miocene Leads (Oil and Gas) Prospective Resources are assigned to twelve leads (Table 6.11), distributed over OML 120 and 121 in a series of combination structural-stratigraphic traps in reservoirs of Miocene to Pliocene age. 6.4.1 Ereng B

Ereng B Lead is discussed in conjunction with the Ereng A prospect (see section 6.1.2).

6.4.2 Ewo Deep

The Ewo Deep Lead lies beneath the Ewo-1 well (Figure 6.24) which was not completed to target depth because of mechanical problems. It lies in approximately 650 m water depth. Correlations are tentative but the reservoir target is in the Middle to Lower Miocene, slightly older than the targets at the prospects Ewo North UT and Ereng. Top reservoir is mapped as Horizon 1 and


77

the base of the unit containing potential reservoir is designated as Horizon 1A. This latter is an unconformity surface post-dating an earlier phase of faulting.

TABLE 6.11

SUMMARY OF UNRISKED PROSPECTIVE RESOURCES (LEADS) NIGERIA AS AT 30th JUNE, 2013

Lead Reservoir

Gross Unrisked Prospective Resources - Leads Best

Estimate


(%)


Prospective Resources - Leads Best

Estimate GCoS

(%)

Oil / Cond

(MMBbl) Gas

(Bscf) Oil /

Cond (MMBbl)

Gas (Bscf)

Kigbo Deep Top Miocene 0 254 30 0 76 10 R Plio / Pleistocene 0 60 30 0 18 15 ONIGU Plio / Pleistocene 0 162 30 0 49 15 Eba Lower Pliocene 37 37 30 11 11 15 Songu Pliocene 0 40 30 0 12 15 M Plio / Pleistocene 10 26 30 3 8 11 A East Mid-Late Miocene 53 210 30 16 63 11 A West Mid-Late Miocene 19 95 30 6 28 11 C Mid-Late Miocene 29 133 30 9 40 11 D Mid-Late Miocene 62 281 30 19 84 11 Ereng B Mid-Late Miocene 170 195 30 51 58 9 Ewo Deep Mid Miocene 164 0 30 49 0 9 Notes: 1. Leads are features that are not sufficiently well defined to be drillable, and need further work and/or




4. “Net Prospective Resources (Leads)” in this table are Company’s Working Interest fraction of the Gross resources; they assume that CAMAC elects to invest at its full working entitlement under the terms of the sharing agreement between CAMAC and Allied.


78

FIGURE 6.24

VERTICAL SEISMIC SECTIONS THROUGH EWO DEEP LEAD

The lead lies at the edge of the Ewo survey and it also suffers because of blanking of the data beneath shallow gas-bearing units and beneath major fault planes (Figure 6.24 lower image). This lead is situated in the footwall of a major young fault to the west, but closure in a north-south direction results from a series of older Miocene fault terraces, oriented approximately NE-SW. The main reservoir drapes over these to create a dip closure to the north and a possible fault truncation to the south. Within the sediment package there are indications of channelized sand bodies and elevated amplitudes towards the base of the interval mapped. As a result of the lack of clear definition of the limits of the potential reservoir and the controls on the trap, Ewo Deep is defined as a lead at this stage. A single case volumetric case has been calculated, based on the limit of the elevated amplitudes within the Horizon 1 unit. The key uncertainty is definition of


79

the trap and of the distribution of reservoir (Figure 6.25). Beneath the Horizon 1A unconformity surface, there is at least one package of seismic amplitudes that may represent potential sandstone units which might, with further mapping, develop into a separate play.

FIGURE 6.25

CONTOURED DEPTH STRUCTURE TOP EWO DEEP HORIZON 1 AND RMS

AMPLITUDES FOR BULK INTERVAL BETWEEN HORIZON 1 AND 1A


80

6.4.3 Lead A

Lead A is a combination structural and stratigraphic type lead, located on the east and west flanks of a north to south trending shale ridge (Figure 6.26). CAMAC has used 3D data to map prospective intervals at four separate levels in the Middle to Late Miocene, The lead is located in approximately 400 m of water depth and extending northwards from Oyo West. GCA’s review of the seismic data over the lead confirms the overall form of the trap. Analysis of seismic amplitudes in the area where the horizons pinch-out onto the east and west flanks of the shale ridge is made difficult by steeply dipping beds and overlying amplitudes obscuring the data below. Therefore the exact location of the pinch-out for each of the mapped horizons on to the shale diaper/ridge is very difficult to map with any confidence. At the shallower prospective intervals (Top Miocene and Miocene Horizon 2) there may not be any pinch-out at all. Towards the crest of the shale ridge there are a series of faults, some of which may provide seal at this location. Pinch-out of the deeper Miocene horizons onto the shale ride is more likely, though with current data is difficult to quantify. The key risk for Lead A is trap definition. It is believed that CAMAC hopes to reprocess the 3D seismic data, which should help resolve the lead in more detail, in an attempt to elevate Lead A to prospect status. Mixed phase oil and gas hydrocarbons may be expected to be present at all levels of Lead A. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


81

FIGURE 6.26

VERTICAL SEISMIC SECTION THROUGH LEAD A WITH CONTOURED TIME MAP ON TOP MIOCENE HORIZON


82

6.4.4 Lead C

Lead C is a combination structural and stratigraphic type lead, located in Licence OML 120, on the south west flank of a large shale diapir (Figure 6.27). CAMAC has proposed prospective intervals at four separate levels in the Middle to Late Miocene, each prospective interval has been mapped on the 3D dataset. The lead is located in approximately 300 m of water depth and extending south east from the Oyo field. GCA’s review of the seismic data confirms potential at the four seismic mapping intervals. Similar to Lead A, the exact location of the pinch-out is uncertain; however it is likely that pinch-out of occurs onto the shale diapir (Figure 6.27). Analysis of seismic amplitudes in the area where the horizons pinch-out onto the shale diapir is made difficult by steeply dipping beds and overlying amplitudes obscuring the data below. Towards the crest of the shale ridge there are a series of faults, some of which may provide seal at this location. East west trending faults are required to provide seal to the north at all mapping horizons and are difficult to map. The key risk for Lead C is trap definition. It is currently believed that CAMAC expects to reprocess the 3D seismic data, which should help resolve the lead in more detail. Mixed phase oil and gas hydrocarbons may be expected to be present at all levels of Lead C. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


83

FIGURE 6.27

VERTICAL SEISMIC SECTION THROUGH LEAD C WITH CONTOURED TIME MAP ON TOP MIOCENE HORIZON


84

6.4.5 Lead D

Lead D is similar to Leads A and C where four Middle to Upper Miocene intervals have been mapped by CAMAC to form a combination structural and stratigraphic trap located on the flank of large shale diaper. Lead D is located in Licence OML 120, on the east flank of a shale diapir (Figure 6.28). The lead is situated in approximately 270 m of water depth, 1.5 km to the east of the Oyo field. Review of the 3D seismic data confirms potential at the four seismic mapping horizons. The upper two prospective intervals at Lead D (Top Miocene and Miocene Horizon 2) require fault seal at the crest of the structure and pinch-out onto the shale diapir further to the north (Figure 6.28). The deeper two prospective intervals (Miocene Horizon 3 and Top Middle Miocene), are proposed to pinch-out directly onto the shale diapir to the west and also rely fault seal of east to west trending faults to the north. Similar to other leads of this type, the exact location of the pinch-out is uncertain, however it is likely that pinch-out of CAMAC’s deeper Miocene horizons occurs onto the shale diaper, due to the diapir’s vertical extent (Figure 6.28). Analysis of seismic amplitudes in the area where the horizons pinch-out onto the flank of the shale diapir is made difficult by steeply dipping beds and overlying amplitudes obscuring the data below. The key risk for Lead D is trap definition. Reprocessing the 3D seismic data should help resolve the lead in more detail. Mixed phase oil and gas hydrocarbons may be expected to be present at all levels of Lead D. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


85

FIGURE 6.28

VERTICAL SEISMIC SECTION THROUGH LEAD D WITH CONTOURED TIME MAP ON TOP MIOCENE HORIZON


86

6.5 Eastern OML 121: Pliocene to Pleistocene Leads (Gas) 6.5.1 Lead R

Lead R is located towards the east of licence OML 121, in approximately 350 m of water depth and 10 km to the north west of the Ebolibo-1 gas discovery well. CAMAC has interpreted the prospect at the H110 (Plio/Pleistocene) seismic interval, which is a similar stratigraphic interval to the pay zones encountered at the Ebolibo-1 well. Lead R is characterised by strong amplitude responses, which are similar to that observed at the Ebolibo-1 discovery well. Lead R is located in a fault block created by two faults trending in an east to west direction associated with a large growth fault, which trends in a south east to north west direction (Figure 6.29). Lead R appears to be trapped to the north by a (recent) east to west fault, there is sharp amplitude shut-off across the fault from south to north. The amplitude dies out to the south, where the amplitude is coincident with structure contours. Prospect R is located in an area considered to be prone to charge with gas phase hydrocarbons. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


87

FIGURE 6.29

VERTICAL SEISMIC SECTION THROUGH LEAD R WITH TIME CONTOURED MAXIMUM AMPLITUDE MAP AT H110

S

H110

N

Lead R

0 1 2 km

N

S

0 1 km


88

6.5.2 Onigu Lead Onigu is located in the north east of licence OML 121, 10 km due north of the Ebolibo-1 discovery well. Onigu is situated in approximately 200 m of water at the H114 (Plio/Pleistocene) stratigraphic interval. The lead is characterised by amplitude brightening into a north to south trending normal growth fault, where the lead is situated in the footwall block of the fault. Unlike some of the other gas prone leads/prospects in this area the character of the seismic response is not the same as that observed at Ebolibo where there is a strong trough-peak-trough character, and amplitude shut-off is coincident with structure contours. The seismic response at Onigu is not always trough-peak-trough and the amplitude shut-off is not consistent with a structural contour. CAMAC has defined an area of nearly 6 km2 at Onigu, which could be refined to a smaller area that encompasses just the amplitude anomaly (Figure 6.30). The lead relies on fault seal to the south and east and lateral pinch-out or facies change to the north, which is not well supported by the seismic data. Key geological risks for the Onigu lead are associated with the various sealing mechanisms. Gas phase hydrocarbons are expected at Onigu. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


89

FIGURE 6.30

VERTICAL SEISMIC SECTION THROUGH ONIGU WITH TIME CONTOURED MAXIMUM AMPLITUDE EXTRACTION FROM H114


90

6.5.3 Eba Lead

Eba is located in the north of licence OML 121, 15.8 km due south of the Oyo field in approximately 480 m of water depth. Eba is interpreted at the H150 (Lower Pliocene) interval, which is a similar stratigraphic interval to the producing Oyo field. The Eba lead is proposed to consist of a broad east to west trending canyon that appears to be at least partially filled with sand prone facies (Figure 6.31). Seismic data indicate that the base of the channel (oldest infill) is composed of brighter seismic amplitudes and reflector geometries, indicative of sandy facies. The upper section of the channel infill is generally lower amplitude and more laterally continuous, indicative of deeper water, less sand prone facies. Eba relies on lateral stratigraphic seal to the north west, fault seal to the south west and seal against mud diapir and or faulting to the east. Therefore key geological risks for Eba are associated with the multiple seal types required in order to trap hydrocarbons. There is subtle evidence of a flat cross cutting event, which may be a direct hydrocarbon indicator as is observed in certain other prospects in OML 120 and 121, though it is certainly less clear at Eba. The hydrocarbon phase expected at Eba is mixed gas and oil phase hydrocarbons. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


91

FIGURE 6.31

VERTICAL SEISMIC SECTION THROUGH EBA WITH CONTOURED TIME MAP


92

6.5.4 Songu Lead

The Songu Lead is located in the northern central area of OML 121, in 450 to 500 m of water column. The lead is interpreted at the H124 (Pliocene) seismic horizon as three independent amplitude anomalies, which brighten close to normal faults. Two of the amplitude anomalies are located in footwall locations and the third (and largest) amplitude anomaly is located in the hangingwall of a large normal fault trending south east to north west (Figure 6.32). The two anomalies in footwall blocks (Figure 6.32) show amplitude shut-off down dip roughly coincident with structural contours. The anomaly furthest to the east in the hangingwall block of a normal fault is a stratigraphic anomaly and the amplitude shut-off is not coincident with structural contours. The seismic character of the amplitude anomalies is trough-peak-trough, similar to that observed at the top of the Ebolibo gas discovery, which is approximately 23 km to the south east. GCA agrees with CAMAC that the Songu lead is likely to be charged with gas phase hydrocarbons. Figure 6.33 shows a linear amplitude anomaly located 1 km to the south of Songu, which trends from north east to south west, which has a similar trough-peak-trough seismic character to Songu. No volumes are carried by CAMAC for this feature, but may offer further potential. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


93

FIGURE 6.32

VERTICAL SEISMIC SECTION THROUGH SONGU WITH CONTOURED TIME MAP


94

6.5.5 Lead M

Lead M is located in the far south of OML 121 in 400 to 420 m of water depth. Lead M is interpreted below the H114 (Plio/Pleistocene) seismic marker, 15 km to the west of the Ebolibo discovery and 2 km west of the Kigbo Prospect. The seismic data appears to indicate that there may be a slightly more sand prone package towards the top of CAMAC’s channel/slump package, which gives an area of approximately 3.3 km2 (Figure 6.33). The thickness of the more sand prone package is interpreted to be approximately 50 m. The down-dip amplitude is not coincident with structural contours. The lead would rely on a number of geological factors to combine in order for an effective seal to be made, which include; lateral facies change/pinchout, faulting and/or mud diapirism. The hydrocarbon phase expected at Lead M is mixed phase. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


95

FIGURE 6.33

VERTICAL SEISMIC SECTION THROUGH LEAD M WITH TIME CONTOURED MAXIMUM AMPLITUDE EXTRACTION AT TOP M CHANNEL HORIZON


96

6.6 OML 120: Miocene Leads 6.6.1 Kigbo Deep Lead

CAMAC has interpreted Kigbo Deep at the regional Top Miocene stratigraphic interval. The Kigbo Deep Lead is situated partially below the Kigbo prospect (Figure 6.34) and straddles the boundary between licences OML 121 and OPL 284-DO to the south, approximately 10 km to the west of the Ebolibo-1 discovery well. Kigbo Deep is located in the down-thrown block (to the south) of a large normal fault and is interpreted by CAMAC to be a dipping stacked pay system, trapped by a combination of faulting and mud diapirs to the north and west. The definition of the trap at Kigbo Deep is uncertain over the majority of CAMAC’s polygon outline; mainly due to the poor resolution of the seismic data. There are several possible reasons for the lack of resolution within the area of the lead, which include; overlying bright amplitudes absorbing seismic energy; steeply dipping beds; faulting and or mud diapirism. Therefore the key risk for Kigbo Deep is trap definition. The imaging of the Kigbo deep lead may be improved through reprocessing of the seismic data. Due to Kigbo Deep’s location with respect to thermal maturity mapping results, GCA has calculated gas phase hydrocarbons. Gross and net best case estimates of Prospective Resource volumes and the GCoS are presented in Table 6.11.


97

FIGURE 6.34

VERTICAL SEISMIC SECTION THROUGH KIGBO DEEP LEAD WITH CONTOURED TIME MAP


98

7. GAMBIA 7.1 Background CAMAC operates two offshore blocks in Gambia (West Africa) with a 100% working interest. Block A2 is 1,282 km2 and is immediately north of Block A5 which is 1,383 km2 in area (Figure 7.1). Water depth varies greatly from 50 m in the east, deepening rapidly to approximately 1,000 m in the west. Operations are governed by a PSC with the Gambia National Petroleum Company (GNPC), signed in May 2012. The initial exploration period runs for a term of four years (to 2016) and has a number of work commitments, each to be carried out on both Blocks A2 and A5. Work commitments for the initial period are; a regional geological study; acquisition of 750 km2 3D seismic data; drilling of one exploration well and evaluation of the results. Following a successful completion of the initial exploration phase, it would be possible to enact the first of two possible extension exploration periods; each has a period of two years. Both periods have minimum work commitments to be carried out on both blocks, which are: preparation work for drilling; drilling one exploration well and evaluating the results. 7.2 Geological Setting The blocks lie on the Northwest African passive margin. The overall stratigraphy is presented in Figure 7.2. Triassic syn-rift deposits are followed by early Jurassic volcanism and oceanic break-up. Lower Jurassic salt may be present but is probably not significant in the vicinity of Blocks A2 and A5. A major aggrading Jurassic to Lower Cretaceous shelf edge runs through block. This is strongly controlled by basement faulting and controls carbonate facies. Shelf clastics of Albian to Cenomanian age are succeeded by major uplift and or eustatic fall at the base Senonian. Erosional incision led to re-localisation of clastic reservoirs into deeper water, followed by transgressive drowning of the modified shelf margin and continuing passive margin sedimentation through Upper Cretaceous to Tertiary. Marine source rocks occur in Lower Jurassic, possibly Upper Jurassic, and in the Albian to Turonian.


99

FIGURE 7.1

LOCATION OF CAMAC BLOCKS, GAMBIA

A2

A5

Source: Deloittes


100

FIGURE 7.2

STRATIGRAPHIC SUMMARY, OFFSHORE GAMBIA

7.3 Exploration History These blocks are immature in terms of modern exploration, but are on the same geographical trend as the maturing West African margin acreage to the south. One well has been drilled on Block A2. The Jammah-1 well was drilled by Chevron 1979, to a depth of 3,020 m, targeting Cenomanian and Albian trapping structures (Table 7.1). This well encountered a thick, high quality reservoir with gas shows and was subsequently plugged and abandoned. There have been no wells on Block A5, but four wells have been drilled on Senegal acreage to the south. Africa Petroleum plans to drill Blocks A1 and A4, immediately to the east in 2013. CAMAC provided an IHS Kingdom project to GCA, which contained a number of multi-vintage, variable quality, 2D seismic data. This provides sparse coverage (2 km to 5 km

Triassic syn-rift sequence

Albian-Cenomanianreservoirs

Upper Cretaceous-Tertiary deep water

reservoirs

Aggrading Jurassic-Lower

Cretaceous shelf complex

Source Rock

Reservoir Rock

Proven plays in basin

NEOGENE

PALAEOGENE

UPPER CRETACEOUS

LOWERCRETACEOUS

JURASSIC

TRIASSIC

PALAEOZOIC


101

line spacing) to Blocks A2 and A5. The project also included CAMAC’s latest interpretations and polygonal outlines of areas of interest.

TABLE 7.1

EXPLORATION WELLS GAMBIA


Jammah-1 Block A2 Chevron 1979 P and A. Gas shows in several units in Maastrichtian, Cenomanian and Albian 3,020

7.4 Prospective Resources Two leads are defined by CAMAC, designated West and East. Both are located within the shelfal area of the Cretaceous sequence and have potential inferred in intra-Cenomanian sandstones and Albian sandstones, observed in Jammah-1. 7.4.1 West Lead

The West Lead is a structural trap in the footwall block of a major shelf margin fault, mostly within Block A5, but with upside in Block A2 (Figure 7.3). It appears entirely dip closed as the base Senonian unconformity does not cut as deeply in this location as at Jammah-1 further north, but there is a possibility that local incision to Cenomanian level may influence the trap and seal. Trap definition uncertainty mostly results from the depth conversion in the region of rapidly changing water depth over the present day shelf edge, and the lead may prove to be part of a complex of further structurally high areas, linking through to the Jammah-1 area.


102

FIGURE 7.3

CAMAC LEAD PORTFOLIO, GAMBIA

Thick Cenomanian shelf sandstone reservoirs occur at Jammah-1 and at Diola-1 and Casamance Maritime-4, to the south of Block A5, sealed by Upper Cenomanian to basal Turonian mudstones. Upper Albian sandstones are also observed at Jammah-1, sealed by Lower Cenomanian mudstones. Although gas shows are recorded at Jammah-1, no oil was reported and hydrocarbon charge remains in doubt. Although some suggestions of shallow gas exist, direct indications of hydrocarbons cannot be defined with confidence from the 2D dataset of only moderate quality. Upper Cretaceous source rocks are immature in this region of the shelf edge and long distance migration is necessary from deeper water kitchens; although it is noted that base Senonian erosion may have removed the Cenomanian to Turonian source rock intervals immediately to the west. Further west, declining source quality and thickness, and the passage into the oceanic regime with lower heat flows, may limit the possibility of major source kitchen development. The possibility of Upper or Lower Jurassic source


103

rocks, proven elsewhere on the North African Atlantic margin, has not been evaluated. Indicative volumes and assessment of the geological chance of success are presented below. Estimates of gross rock volume within the lead are based on interpretation conducted by CAMAC, with an examination of sensitivities in the mapping process. It is assumed that the closure will be full to the mapped spill point and that reservoir parameters for the proposed Cenomanian and Albian reservoirs will be similar to those at Jammah-1. An oil case is assumed, based on regional information. The key issues of risk are the structural trap definition after depth conversion, and the hydrocarbon charge model. With regard to the former issue, it is expected that closer resolution of depth structure may lead to further trap definition along the shelf margin trend beyond the lead currently defined.

7.4.2 East Lead

The East Lead straddles the A2 block boundary to the east (Figure 7.3). The seismic data show a large regional structural nose plunging to the south, and the lead lies on the flank of this. Critical to trap definition is demonstrating that the structural nose closes to the north and at this time, there is no clear indication of this with the present dataset. No volumetric significance is attached to this area at present, but the possibility of closures on the flanks of the regional structural nose remains to be further investigated.

TABLE 7.2

SUMMARY OF UNRISKED PROSPECTIVE RESOURCES (LEADS)

GAMBIA AS AT 30th JUNE, 2013

Block Lead

Gross Unrisked Prospective

Resources - Leads Best Estimate


(%)


Prospective Resources - Leads

Best Estimate GCoS

(%)

Oil / Cond (MMBbl)

Gas (Bscf)

Oil / Cond

(MMBbl) Gas

(Bscf)

A2 West: Intra Ceno. 160 0 100 160 0 5 A2 West: Albian 65 0 100 65 0 5 Notes: 1. Leads are features that are not sufficiently well defined to be drillable, and need further work and/or





104

8. KENYA 8.1 Background CAMAC operates 4 blocks in Kenya, in all cases with a 100% working interest, although the National Oil Company of Kenya (NOCK) has an option to exercise a participating interest of up to 20% following discovery and approval of any development plan. Block L1B is entirely onshore and covers a large area of 12,128.75 km2. It lies in the Lamu Basin towards the centre of eastern Kenya in the Duruma Wajir Lowland, a dissected low plateau, with residual hills up to approximately 400 m in height. Somalia is directly to the east of the western block boundary (Figure 8.1). It is served by the B8 major highway which transects the western part of the block, linking the town of Garissa, immediately to the north with the coast. Block L16 (Figure 8.1) straddles the coast, totalling 3,613 km2, with approximately 2,100 km2 onshore and 1,500 km2 offshore, although it is considered an onshore block for purposes of the contractual terms. Water depths are shallow shelf in the north and west, ranging up to approximately 500 m in the far southeast of the block. The onshore portion of the block is low lying coastal plain. Although the precise operational impact cannot be verified, Block L16 partly contains areas designated as the Arabuko Sokoke Forest Reserve (420 km2), within which there is the small Arabuko Sokoke National Park (approximately 6 km2). Offshore, it also contains the Watamu and Malindi Marine National Reserves small (approximately 10 km2) areas conserving the coastal and shallow marine environment.


105

FIGURE 8.1

LOCATION OF CAMAC BLOCKS, KENYA

L-01B

L-16

L-27

L-28

Source: Deloittes


106

Blocks L27 and L28 are further offshore with water depths ranging up from approximately 2,200 m to 4,000 m. Each block has an area of 10,585.62 km2. The onshore blocks (L1B and L16), PSCs were signed by CAMAC in May, 2012 with an initial exploration period of two years. Within this there is a requirement for each block to acquire and process 1,000 km2 of gravity and magnetic data and to acquire, process and interpret 500 line km of new 2D seismic data. The first of these items is now complete and interpretation products received. The first exploration period may be followed by two extensions, each of two years. For both blocks the work obligations of the extension periods are to acquire process and interpret 3D seismic data and the drilling of exploration wells (Table 8.1). There is also a requirement to relinquish 25% of the area of each block before or at the end of the initial exploration period and then a further 25 % from each block before or at the end of the first additional exploration period.

TABLE 8.1

WORK COMMITMENTS ONSHORE BLOCKS L1B AND L16, KENYA

Period Duration New Geophysical Data Wells

1st 2 years 1,000 km2 of gravity and magnetics 500 line km of 2D seismic

2nd 2 years 300 km2 of 3D seismic One well to 3,000 m

3rd 2 years 150 km2 of 3D seismic One well to 3,000 m

For the offshore blocks (L27 and L28), the PSC was also signed in May, 2012 but the initial exploration period is for three years. During this there is a requirement to conduct geological and geophysical studies using existing data, to reprocess and re-interpret existing 2D seismic data on the block and to acquire, process and interpret 1,500 km2 of 3D seismic data. No substantial data purchase or acquisition has yet been completed in the offshore blocks. The first exploration period may be followed by two renewals of two years each, during which the drilling of exploration wells is required (Table 8.2). There is also a requirement to relinquish 25% of the area of each block before or at the end of the initial exploration period and then a further 25 % from each block before or at the end of the first additional exploration period.

TABLE 8.2

WORK COMMITMENTS OFFSHORE BLOCKS L27 AND L28, KENYA

Period Duration G and G studies New seismic data Wells

1st 3 years Integrated G&G studies

Reprocess and interpret existing 2D seismic data

1,500 km2 of 3D seismic data

2nd 2 years One well to 3,000 m

3rd 2 years One well to 3,000 m


107

8.2 Geological Setting The onshore blocks lie in the Lamu Embayment sedimentary basin (Figure 8.2). Initial “Karroo” rift sediments of Permian to Lower Jurassic age underlie a post rift to drift sequence associated with the opening of the Western Indian Ocean via the southward displacement of Madagascar along the Davie Fracture Zone, initially in the Middle Jurassic. Passive margin sedimentation was influenced onshore by the propagation of the Central African Rift system into the area from the northwest, and there are anomalously thick sediments of Lower Cretaceous age. Continuing Late Cretaceous to Recent passive margin subsidence and sedimentation was interrupted by major uplift of latest Cretaceous to early Tertiary age that led to substantial erosion. The offshore blocks are located to the east of the northward continuation of the Davie Fracture Zone and are interpreted to lie on oceanic crust of Middle to Late Jurassic age. Localised seamounts representing continuing volcanic activity occur in the general area, although have not been mapped within the blocks themselves.

FIGURE 8.2

STRATIGRAPHIC SUMMARY, LAMU EMBAYMENT BASIN

Amboni Formation

Kofia Formation

Hagarso Formation

Karroo Sequences

AGE LITHOLOGY SENWMEGA SEQ.

Locally absent section on

principal highs

TER

TIAR

YC

RET

ACEO

US

JUR

ASSI

C

PLIOCENE

MIOCENE

OLIGOCENE

EOCENE

PALEOCENE

UPP

ERLO

WER

SENONIAN

TURONIANCENOMANIAN

ALBIAN

APTIANBARREMIAN

NEOCOMIAN

MALM

DOGGER

LIAS

TRIASSIC

PERMIAN KEN 3

KEN 5

KEN 6

KEN 8

KEN

10

KEN

12

KEN

13

KEN

14

KEN 15


108

8.3 Exploration History 8.3.1 Block L1B

One well has been drilled on Block L1B, and there are three wells on L1A, to the north (Table 8.3).

TABLE 8.3

EXPLORATION WELLS BLOCKS L1B AND L1A, KENYA


Hagarso-1 Block L1B Texas Pacific 1975 P and A. Dry. Trace gas

shows only in Upper Cretaceous.

3,092

Garissa-1 Block L1A BP-Shell Petroleum

Development Company

1968 P and A. Dry no shows 1,240

Kencan-1 Block L1A Petro Canada Resources 1986 P and A. Dry no shows 3,863

Wal Merer-1 Block L1A BP-Shell Petroleum

Development Company

1967 P and A. Gas shows reported in Cretaceous. 3,794

CAMAC has access to approximately 1,750 line km of previous 2D seismic data on Block L1B and additional seismic data on L1A.

8.3.2 Block L16

There has been no previous drilling on Block L16. The nearest relevant wells are to the east at Maridadi-1, Simba-1 and Mbawa-1, and to the west at Rio Kalui-1. CAMAC has access to no seismic data for this block.

8.3.3 Blocks L27 and L28

There has been no previous drilling on Blocks L27 and L28. The nearest wells are in blocks to the west at Simba-1 and Mbawa-1 (Table 8.4).

TABLE 8.4

EXPLORATION WELLS BLOCKS L06, L10A, L08 AND L19, KENYA


Maridadi-1B Block L6 Cities Service 1982 P and A. Gas shows in the Tertiary. 4,198

Simba-1 Block L10A Total 1978 P and A. Gas shows in

Tertiary and Cretaceous 3,604

Mbawa-1-1 Block L8 Apache 2012 Gas discovery from Upper Cretaceous sandstone 3,151

Rio Kalui-1 Block L19 Mehta and Co 1962 P and A. Oil staining in Karoo sequence 1,538


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The recent discovery at Mbawa-1 is the first offshore hydrocarbon discovery in Kenya. CAMAC has access to no seismic data for this block, but adjacent regional 2D lines provide guidance.

8.4 Prospective Resources 8.4.1 Block L1B

Interpretation of Block L1B is based on the previous wells drilled on Blocks L1A and L1B, on the sparse, moderate quality, 2D seismic data grid (limited to the centre of the block) and preliminary inferences from regional gravity data. Block L1B lies on the Garissa High, a complex of extensional and inverted fault blocks, with culminations in the area of the Garissa-1 and Kencan-1 wells, and in the south around the Hagarso-1 well. Rocks at surface are Pliocene to Quaternary in age. The Garissa High plunges southwards from Garissa-1, where lower Tertiary rocks unconformably overlie Middle Jurassic. The Cretaceous section thickens moving southward. The area is characterised by a series of approximately WNW-ESE trending faults and lineaments. The north east of the block shows a series of fault terraces stepping down into the area of the Wal Merer-1 well, where a considerable thickness of Lower Cretaceous section is preserved. Hydrocarbon indications are limited to minor trace gas shows in the Cenomanian to Turonian section at Hagarso-1 and in the sandstones immediately beneath the Base Tertiary unconformity at Kencan-1. There is also carbonaceous material associated with dolomites, possibly pyrobitumen, in the Middle Jurassic dolomites of the Amboni Formation at Garissa-1. There are no clearly defined source rock horizons in the wells drilled, but mixed oil and gas source potential is inferred from regional data in the Upper Cretaceous. Levels of thermal maturity are interpreted to be high, with greater chance of gas than oil in the area previously drilled. Reservoirs consist of the Middle Jurassic Amboni Limestone, limestone and minor sandstones of the Albian Hagarso Formation and minor sandstones in the Lower Kofia Formation of Turonian age. Reservoir quality in the Lower Cretaceous and Jurassic is poor and poor to moderate in the Upper Cretaceous. General lead areas can be defined as structural dip closures within the complex of fault blocks that comprises the Garissa High. These are not yet sufficiently well-defined to permit an estimate of their volumetric potential, but three areas can be defined which can be considered as envelopes containing areas of more complex trap potential whose areas range from 17 to 148 km2. Although these structural lead areas have been defined and provide an indication of potential trap size, there is the risk of encountering a similarly unproductive section as that seen at the previous wells to north and south. More significant prospectivity lies in the fault terraces to the north, potentially containing an expanded Cretaceous and Upper Jurassic section. No leads or prospects are defined by CAMAC in this area. Camac estimate there is exploration potential in Jurassic sediments below the section penetrated in Hagarso-1, however there is no quantitative data available to GCA to estimate prospective resource volumes in this section.


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Despite some previous activity, the potential of the area has not been fully evaluated. The key risks are the unproven hydrocarbon source in the area, and over-maturity of the Lower Cretaceous and older sections. Reservoir quality is expected to be poor in rocks within and older than the Lower Cretaceous section.

8.4.2 Block L16

No seismic data are available to CAMAC for Block L16. Inferences on prospectivity are drawn from regional data alone. “Karroo” rocks of Triassic and Lower Jurassic age crop out in the west of the block overlain to the east by a series of Middle Jurassic to Lower Cretaceous passive margin rocks. These appear truncated by Lower Tertiary erosion, especially along a high in the north of the block, followed by onlapping and overstepping Miocene to Pliocene deposits. The coastal zone comprises Quaternary outcrop. Offshore, the central/northern high continues, oriented approximately WNW-ESE, to the south of which is a gravity low inferred as a sedimentary basin containing Middle Jurassic evaporites, deposited close to the break-up unconformity. Sediment thickness is estimated up to approximately 8 km. Petroleum source rocks may exist in a number of stratigraphic levels including the syn-rift “Karroo” sequences of Permian to lower Jurassic age, Lower Cretaceous, Upper Cretaceous and Eocene. The older source rocks are probably gas-prone and/or gas to over mature. The best opportunity for a mixed oil and gas charge comes from the Upper Cretaceous petroleum system. Principal reservoirs are expected to be sandstones of Upper Cretaceous to Lower Tertiary age, which are proven hydrocarbon-bearing and productive to the east. Trapping may arise from a combination of extensional structuring, inversion, salt-related structures and stratigraphic closures in Upper Cretaceous to Paleocene sands. The key uncertainty surrounds proving a viable petroleum system on the block and the controls on the distribution and preservation of the main Upper Cretaceous to possibly Lower Tertiary reservoirs. No leads or prospects have been defined for Block L16 by CAMAC.

8.4.3 Blocks L27 and L28

Inferences on the prospectivity of the blocks are drawn from the adjacent seismic data (in particular lines MCS_06A, MCS_06B and MCS_08), and from regional analogues and overall fairways inferred from regional data. CAMAC does not currently have access to the very small amount of 2D seismic data that exists on block L27 and L28, with the exception on one regional 2D seismic line that runs along the southern boundary of Block L28. The principal hydrocarbon source rocks in the area are expected to be Upper Cretaceous age and are mixed oil- and gas-prone. Additional potential source rocks are inferred of Lower Cretaceous age, although more gas prone, and there are rich, oil-prone Eocene source rocks. Levels of maturity are not proven on Blocks L27 and L28, but there is greater chance of maturity commensurate with oil or gas generation in the west of the block where sedimentary thickness above oceanic basement is greater. The risk of hydrocarbon maturity is greatest for the Tertiary source rocks


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Potential reservoirs occur in Upper Cretaceous and Lower Tertiary sandstones. A mobile, overpressured shale unit occurs, possibly of Upper Cretaceous age, which has led to local diapirism and to the development of a decollement surface, above which a series of contractional faults and folds have created a series of potential traps in the Upper Cretaceous and lower Tertiary units. Extensional structural traps may occur beneath this mobile mudstone layer. Care must be exercised in applying direct analogues from the adjacent Simba-1 and Mbawa-1, as these lie on continental or transitional, rather than oceanic crust. Structuration at these wells appears principally to be as a result of relatively late Tertiary inversion to create broad regional highs and this process may have influenced trap formation on Blocks L27 and L28. Deepwater sandstone bodies of Lower Tertiary and Upper Cretaceous age may also contribute to a stratigraphic component of trapping. The key uncertainty is the identity of petroleum source rocks and the localisation of source kitchens in an oceanic environment of low geothermal gradient. No leads or prospects have yet been defined for Blocks L27 and L28.

9. ECONOMICS GCA has conducted economic analyses on the Reserves pertaining to CAMAC. As these are only associated with OML 120 and 121 in Nigeria, only the fiscal terms relevant to those blocks are discussed herein. The licences held in Gambia and Kenya are under Production Sharing Contracts but no summary of these has been provided herein. GCA has conducted economic evaluations of the three production forecasts for the Oyo field. These evaluations were prepared for the purpose of deriving the economic limit test for reserves estimation. In preparing its evaluation, GCA has modelled the applicable fiscal terms based on GCA’s understanding of the fiscal and contractual terms governing the property. The value of physical assets, i.e. plant and equipment, has not been attributed separately as their value has been implicitly included in the assessment of Economic Limit Test (ELT) as part of the petroleum property rights relating to CAMAC’s interest in the Oyo field. The reserves (as at 30th June, 2013) attributable to the net economic interests in Oyo have been derived using the pricing and inflation assumptions described herein. No adjustments have been made for cash balances, inventories, indebtedness or other balance sheet effects, other than those stated herein. GCA has been advised by CAMAC that the planned replacement FPSO contract for the Petrojarl will begin in Q4 2014 and will last for a minimum of 5 years, with options for extensions. 9.1 Fiscal Terms GCA's assessment is based upon GCA's understanding of the fiscal and contractual terms governing the asset Oil Mining Lease (OML) 120 and 121. The OML was granted 27th February, 2001 for a 20 year term under the Petroleum Act 1969.


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Nigerian Fiscal Terms GCA understands that the license is governed by the Nigerian Deep Offshore & Inland Basin Production Sharing Contract (PSC) Act 1999 Terms. The block was awarded on a ‘Sole Risk’ basis with the understanding that the Government reserves the right to a participating interest at any time in the life of the lease. The PSC provides for a 12% royalty payment along with a Petroleum Profit Tax (50% of the Chargeable profit), an Education Tax (2% of Assessable profit), and NDDC tax (3% of capital budget) all of which is paid to the government. CAMAC confirms that a capital allowance of US$1,140 MM is available for PPT calculation. Commercial Agreement between Allied and CAMAC GCA understands that there is a commercial agreement between CAMAC and its partner Allied Energy Resources. CAMAC’s current working interest in the Oyo field is current 30%. The summary of the commercial agreement, as understood by GCA and reflected in the net entitlement, is as follows: • In accordance with this agreement, CAMAC has elected not to participate in any

capital or operating costs for 2013 but thereafter it will pay its equity share of all costs.

• Cost oil is allocated in such quantum as will generate an amount of proceeds

sufficient for the recovery of Operating Costs. Cost Oil Limit is set at 80% after Royalties, PPT, Education and NDDC taxes.

• Cost oil is allocated between Allied and CAMAC based on accumulated operating

costs (defined as all expenditures including past costs as funded by each party. • Profit oil split between Allied and CAMAC is on a 70:30 basis even if CAMAC

elects to pay no costs. In the event that CAMAC contributes to the cost pool, in addition to its 30% share, it gets allocated additional profit oil in the proportion of the actual accumulated operating costs as funded.

In addition to the above, GCA has been provided the following cost pool for cost recovery and profit sharing purpose. Unrecovered cost pool of US$1,010 MM is split as follows:

Allied (US$ MM)

CAMAC (US$ MM)

CAPEX 958.2 - OPEX 48.3 4.2

Total Accumulated cost pool to date of US$1,314 MM is used for profit sharing is split US$1,282 MM to Allied and US$32 MM to CAMAC.


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9.2 Price and Inflation Assumptions GCA has used its in-house Brent price scenario for Q3 2013 and the prices realized/expected from the sale of crude oil produced from Oyo were determined by applying a price differential of +US$1.57/Bbl that reflects quality variation and location against the Brent marker prices in Table 9.1.

TABLE 9.1

GCA BRENT PRICE SCENARIO EFFECTIVE Q3 2013

Year Brent Price

(US$/Bbl) H2 2013 101.29

2014 98.23 2015 94.39 2016 93.37 2017 99.71 2018 101.61

Thereafter 2% inflation Costs are escalated at 2% from 2014. 9.3 Results of Economic Evaluation Economic Limit Test (ELT) Economic Limit as defined by SPE-PRMS is the production rate beyond which the pre-tax net operating cash flows (net revenues minus direct operating costs) from a project are negative; i.e. a point in time that defines the project’s economic life. ELT has been performed taking into account the minimum lease term for the FPSO as advised by the client to be 5 years. In the case of early economic cut-off, the remaining fixed obligation of the FPSO costs would be included in the ELT calculation.

TABLE 9.2

SUMMARY OF OYO FIELD RESERVES ESTIMATE AS OF 30th JUNE, 2013

Category Gross Oil (MMBbl)

CAMAC Net Entitlement Oil (MMBbl)

Total Proved (1P) 10.85 2.8 Proved + Probable (2P) 14.05 3.7 Proved + Probable + Possible (3P) 32.10 7.9 Note: 1. Net entitlement reflects the terms of the agreement between CAMAC and Allied based on a cost oil

+ profit oil basis as described above and also reflects CAMAC’s additional carried interest in past investments.


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10. QUALIFICATIONS GCA is an independent international energy advisory group of 50 years’ standing, whose expertise includes petroleum reservoir evaluation and economic analysis. The report was prepared by GCA staff under the supervision of Mr. Chris Rachwal, aided by Dr. Nick Stronach, Dr. Hanli de la Porte, Ms. Ulamen Verre and Mr. Tom Hancock. The final report was approved at the corporate level by Mr. Brian Rhodes. Mr. Rhodes holds a B.Sc. (Hons) Geology, is a member of the Energy Institute, the Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the European Association of Geoscientists and Engineers, and has more than 39 years’ industry experience. Mr. Chris Rachwal holds a B.Sc. in Geology and a M.Sc. in Petroleum Geology and has more than 36 years’ industry experience. Dr. Stronach has a PhD in Geology, is a UK Chartered Geologist and has 30 years' experience in oil and gas exploration. Dr. de la Porte has a PhD in Petroleum Engineering, is a member of the Society of Petroleum Engineers and has 24 years of industry experience. Ms. Ulamen Verre has a B.Sc. in Economics and Statistics and a M.Sc. in Energy & Environmental Management & Economics and has 12 years of industry experience. Mr. Tom Hancock has a B.Sc. (Hons) in Geology with Ocean Science, is a fellow of the Geological Society of London and a member of the Petroleum Exploration Society of Great Britain and has more than 8 years’ industry experience. 11. BASIS OF OPINION This document must be considered in its entirety. It reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation. In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GCA has not independently verified any information provided by or at the direction of the Client, and has accepted the accuracy and completeness of these data. GCA has no reason to believe that any material facts have been withheld from it, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose. The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

Yours sincerely

GAFFNEY CLINE & ASSOCIATES

Brian Rhodes

Global Director – Corporate Advisory Services


APPENDIX I

Abbreviated form of SPE PRMS

Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers

Petroleum Resources Management System

Definitions and Guidelines (1)

March 2007

Preamble

Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth’s crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.

International efforts to standardize the definition of petroleum resources and how they are estimated began in the 1930s. Early guidance focused on Proved Reserves. Building on work initiated by the Society of Petroleum Evaluation Engineers (SPEE), SPE published definitions for all Reserves categories in 1987. In the same year, the World Petroleum Council (WPC, then known as the World Petroleum Congress), working independently, published Reserves definitions that were strikingly similar. In 1997, the two organizations jointly released a single set of definitions for Reserves that could be used worldwide. In 2000, the American Association of Petroleum Geologists (AAPG), SPE and WPC jointly developed a classification system for all petroleum resources. This was followed by additional supporting documents: supplemental application evaluation guidelines (2001) and a glossary of terms utilized in Resources definitions (2005). SPE also published standards for estimating and auditing reserves information (revised 2007). These definitions and the related classification system are now in common use internationally within the petroleum industry. They provide a measure of comparability and reduce the subjective nature of resources estimation. However, the technologies employed in petroleum exploration, development, production and processing continue to evolve and improve. The SPE Oil and Gas Reserves Committee works closely with other organizations to maintain the definitions and issues periodic revisions to keep current with evolving technologies and changing commercial opportunities. The SPE PRMS document consolidates, builds on, and replaces guidance previously contained in the 1997 Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications, and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources”; the latter document remains a valuable source of more detailed background information., These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that SPE PRMS will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings. It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements. The full text of the SPE PRMS Definitions and Guidelines can be viewed at: www.spe.org/specma/binary/files/6859916Petroleum_Resources_Management_System_2007.pdf

1 These Definitions and Guidelines are extracted from the Society of Petroleum Engineers / World Petroleum Council /

American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) Petroleum Resources Management System document (“SPE PRMS”), approved in March 2007.

RESERVES

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

On Production

The development project is currently producing and selling petroleum to market.

The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project.

Approved for Development

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells.

Justified for Development

Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to

proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of

technical and commercial maturity sufficient to justify proceeding with development at that point in time.

Proved Reserves

Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes:

(1) the area delineated by drilling and defined by fluid contacts, if any, and

(2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved

provided that the locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.

Probable Reserves

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be

in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

Probable and Possible Reserves

(See above for separate criteria for Probable Reserves and Possible Reserves.)

The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally

higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Reserves Developed Reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.

Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing,

(2) wells which were shut-in for market conditions or pipeline connections, or

(3) wells not capable of production for mechanical reasons.

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Undeveloped Reserves

Undeveloped Reserves are quantities expected to be recovered through future investments:

(1) from new wells on undrilled acreage in known accumulations,

(2) from deepening existing wells to a different (but known) reservoir,

(3) from infill wells that will increase recovery, or

(4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to

(a) recomplete an existing well or

(b) install production or transportation facilities for primary or improved recovery projects.

CONTINGENT RESOURCES

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Development Pending

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision

to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.

Development Unclarified or on Hold

A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the

potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.

Development Not Viable

A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.

The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision

not to undertake any further data acquisition or studies on the project for the foreseeable future.

PROSPECTIVE RESOURCES Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. Prospect

A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. Lead A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. Play A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

RESOURCES CLASSIFICATION

PROJECT MATURITY


APPENDIX II

Glossary


GLOSSARY List of Standard Oil Industry Terms and Abbreviations

ABEX Abandonment Expenditure ACQ Annual Contract Quantity oAPI Degrees API (American Petroleum Institute) AAPG American Association of Petroleum Geologists AVO Amplitude versus Offset A$ Australian Dollars B Billion (109) Bbl Barrels /Bbl per barrel BBbl Billion Barrels BHA Bottom Hole Assembly BHC Bottom Hole Compensated Bscf or Bcf Billion standard cubic feet Bscfd or Bcfd Billion standard cubic feet per day Bm3 Billion cubic metres bcpd Barrels of condensate per day BHP Bottom Hole Pressure blpd Barrels of liquid per day bpd Barrels per day boe Barrels of oil equivalent @ xxx mcf/Bbl boepd Barrels of oil equivalent per day @ xxx mcf/Bbl BOP Blow Out Preventer bopd Barrels oil per day bopm Barrels of oil per month bwpd Barrels of water per day BS&W Bottom sediment and water BTU British Thermal Units bwpd Barrels water per day CBM Coal Bed Methane CO2

Carbon Dioxide CAPEX Capital Expenditure CCGT Combined Cycle Gas Turbine cm centimetres CMM Coal Mine Methane CNG Compressed Natural Gas Cp Centipoise (a measure of viscosity) CSG Coal Seam Gas CT Corporation Tax DCQ Daily Contract Quantity Deg C Degrees Celsius Deg F Degrees Fahrenheit DHI Direct Hydrocarbon Indicator DST Drill Stem Test DWT Dead-weight ton E&A Exploration & Appraisal E&P Exploration and Production EBIT Earnings before Interest and Tax EBITDA Earnings before interest, tax, depreciation and amortisation EI Entitlement Interest EIA Environmental Impact Assessment EMV Expected Monetary Value EOR Enhanced Oil Recovery EUR Estimated Ultimate Recovery FDP Field Development Plan FEED Front End Engineering and Design FPSO Floating Production, Storage and Offloading FSO Floating Storage and Offloading ft Foot/feet Fx Foreign Exchange Rate g gram g/cc grams per cubic centimetre gal gallon gal/d gallons per day


G&A General and Administrative costs GBP Pounds Sterling GDT Gas Down to GIIP Gas initially in place GJ Gigajoules (one billion Joules) GOR Gas Oil Ratio GTL Gas to Liquids GWC Gas water contact HDT Hydrocarbons Down to HSE Health, Safety and Environment HSFO High Sulphur Fuel Oil HUT Hydrocarbons up to H2S Hydrogen Sulphide IOR Improved Oil Recovery IPP Independent Power Producer IRR Internal Rate of Return J Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU) k Permeability KB Kelly Bushing KJ Kilojoules (one Thousand Joules) kl Kilolitres km Kilometres km2 Square kilometres kPa Thousands of Pascals (measurement of pressure) KW Kilowatt KWh Kilowatt hour LKG Lowest Known Gas LKH Lowest Known Hydrocarbons LKO Lowest Known Oil LNG Liquefied Natural Gas LoF Life of Field LPG Liquefied Petroleum Gas LTI Lost Time Injury LWD Logging while drilling m Metres M Thousand m3 Cubic metres Mcf or Mscf Thousand standard cubic feet MCM Management Committee Meeting MMcf or MMscf Million standard cubic feet m3d Cubic metres per day mD Measure of Permeability in millidarcies MD Measured Depth MDT Modular Dynamic Tester Mean Arithmetic average of a set of numbers Median Middle value in a set of values MFT Multi Formation Tester mg/l milligrams per litre MJ Megajoules (One Million Joules) Mm3 Thousand Cubic metres Mm3d Thousand Cubic metres per day MM Million MMBbl Millions of barrels MMBO Million barrels of oil MMBTU Millions of British Thermal Units Mode Value that exists most frequently in a set of values = most likely Mscfd Thousand standard cubic feet per day MMscfd Million standard cubic feet per day MW Megawatt MWD Measuring While Drilling MWh Megawatt hour mya Million years ago NGL Natural Gas Liquids N2 Nitrogen NPV Net Present Value OBM Oil Based Mud


OCM Operating Committee Meeting ODT Oil down to OPEX Operating Expenditure OWC Oil Water Contact p.a. Per annum Pa Pascals (metric measurement of pressure) P&A Plugged and Abandoned PDP Proved Developed Producing PI Productivity Index PJ Petajoules (1015 Joules) PSDM Post Stack Depth Migration psi Pounds per square inch psia Pounds per square inch absolute psig Pounds per square inch gauge PUD Proved Undeveloped PVT Pressure volume temperature P10 10% Probability P50 50% Probability P90 90% Probability Rf Recovery factor RFT Repeat Formation Tester RT Rotary Table Rw Resistivity of water SCAL Special core analysis cf or scf Standard Cubic Feet cfd or scfd Standard Cubic Feet per day scf/ton Standard cubic foot per ton SL Straight line (for depreciation) so Oil Saturation SPE Society of Petroleum Engineers SPEE Society of Petroleum Evaluation Engineers ss Subsea stb Stock tank barrel STOIIP Stock tank oil initially in place sw Water Saturation

T Tonnes TD Total Depth Te Tonnes equivalent THP Tubing Head Pressure TJ Terajoules (1012 Joules) Tscf or Tcf Trillion standard cubic feet TCM Technical Committee Meeting TOC Total Organic Carbon TOP Take or Pay Tpd Tonnes per day TVD True Vertical Depth TVDss True Vertical Depth Subsea USGS United States Geological Survey US$ United States Dollar VSP Vertical Seismic Profiling WC Water Cut WI Working Interest WPC World Petroleum Council WTI West Texas Intermediate wt% Weight percent 1H05 First half (6 months) of 2005 (example of date) 2Q06 Second quarter (3 months) of 2006 (example of date) 2D Two dimensional 3D Three dimensional 4D Four dimensional 1P Proved Reserves 2P Proved plus Probable Reserves 3P Proved plus Probable plus Possible Reserves % Percentage

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