AGR TRACS Competent Person s Report on Otakikpo Marginal Field, OML 11, Nigeria, for Lekoil

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1 AGR TRACS Competent Person s Report on Otakikpo Marginal Field, OML 11, Nigeria, for Lekoil Otakikpo Marginal Field Location Map, Niger Delta Peter Chandler, Liam Finch, Simon Moy, Russell Parsons, Ksenia Shmyglia, Bjørn Smidt-Olsen 23 rd

2 This report was prepared in accordance with standard geological and engineering methods generally accepted by the oil and gas industry, in particular the 2007 SPE PRMS. Estimates of hydrocarbon reserves and resources should be regarded only as estimates that may change as further production history and additional information become available. Not only are reserves and resource estimates based on the information currently available, these are also subject to uncertainties inherent in the application of judgemental factors in interpreting such information. shall have no liability arising out of or related to the use of the report. A comprehensive glossary of technical terms, units, and abbreviations commonly used is included at the back of the report. Status Approved Date 23 rd Issued by Peter Chandler Liam Finch Simon Moy Russell Parsons Ksenia Shmyglia Bjørn Smidt-Olsen Approved by Nigel Blott

3 AGR TRACS Competent Person s Report on Otakikpo, OML 11, Nigeria Contents Figures...iv Tables...vi Cover Letter...ix Disclaimer... xiii Executive Summary... xv 1. Introduction Geoscience Review Data available Seismic Interpretation C C C E Depth Conversion and Depth maps C C C E Prospects C5000 Prospects C6000 Prospects C7000 Prospects E1000 Prospects Otakikpo Petrophysics Review AGR TRACS quick-look petrophysical review Otakikpo sums and averages i

4 4. In-Place Volumetric Estimates Otakikpo HIIP estimates Otakikpo Reservoir Property inputs C5000 Volumetric estimates C6000 Volumetric estimates C7000 Volumetric estimates E1000 Volumetric estimates STOIIP and GIIP Summary Otakikpo Prospect HIIP Estimates C5000 Prospects C6000 Prospects C7000 Prospect E1000 Prospects Summary of volumes OML 11 Reservoir Engineering Review Introduction PVT and Fluid Properties Volumetrics and Properties Model Construction Wells Gas liberation Forecast Scenarios Production Profiles Results and Conclusions Further Studies Otakikpo Facilities Review and Cost Estimates Introduction Overview of Otakikpo conceptual Central Production Facilities ii

5 6.3. Otakikpo facilities cost estimates Economic Evaluations Summary of Otakikpo OML 11 Marginal Field Terms Economic Assumptions Economic Evaluations Contingent Resource Estimates Lekoil Net Contingent Resources under $80-$100-$120/bbl AIM Summary Tables Conclusions APPENDIX 1 - Petroleum Resources Classification APPENDIX 2 - Glossary iii

6 Figures Figure 1-1: Location map Otakikpo Marginal Field, OML 11, Nigeria... 1 Figure 1-2: Otakikpo field location within Niger Delta... 2 Figure 1-3: Otakikpo farm-out area, OML Figure 2-1: Location map... 3 Figure 2-2: Line showing well ties... 5 Figure 2-3: C5000 Two-Way Time map... 6 Figure 2-4: Line showing amplitude anomaly... 7 Figure 2-5: C6000 Two-Way Time map... 8 Figure 2-6: C7000 Two-Way Time map... 9 Figure 2-7: E1000 Two-Way Time map Figure 2-8: C5000 Depth structure map Figure 2-9: C6000 Depth structure map Figure 2-10: C7000 Depth structure map Figure 2-11: Sea Floor to E1000 Velocity Function Figure 2-12: E1000 Depth structure map Figure 2-13: C5000 Prospect locations Figure 2-14: C6000 Prospect locations Figure 2-15: C7000 Prospect locations Figure 2-16: E1000 Prospect locations Figure 3-1: CPI plot of C5000 reservoir in Otakikpo Figure 3-2: CPI plot of C6000 reservoir in Otakikpo Figure 3-3: CPI plot of C7000 reservoir in Otakikpo Figure 3-4: CPI plot of E1000 in Otakikpo Figure 4-1: C5000 Reservoir depth map with contacts Figure 4-2: C6000 Reservoir depth map with contacts Figure 4-3: C7000 Reservoir depth map with contacts iv

7 Figure 4-4: E1000 Reservoir depth map with contacts Figure 5-1: Simulation grid showing top surface for the C5000 Horizon Figure 5-2: Cross-sections of C6000 and C7000 reservoirs Figure 5-3: Wells and dual completion scheme Figure 5-4: E1000 Sensitivity of recovery vs. well numbers Figure 5-5: Otakikpo Notional production profiles for the P90-P50-P10 cases Figure 6-1: Location map for planned Otakikpo production facilities Figure 6-2: Conceptual lay-out of proposed Otakikpo CPF Figure 6-3: Conceptual process flow diagram for Otakikpo CPF v

8 Tables Table 0-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil... x Table 0-2: Otakikpo Unrisked and Risked Contingent Resources and net attributable to Lekoil... x Table 0-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited... xi Table 0-4: Otakikpo exploration potential - Summary of 100% Unrisked STOIIPs... xi Table ES-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil xvi Table ES-2: Otakikpo Unrisked and Risked Contingent Resources net attributable to Lekoil... xvi Table ES-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited... xvi Table 2-1: Well to Grid misties (-ve value means grid is deeper than the well) Table 2-2: C5000 Prospect C5 1 Probability of Success Table 2-3: C5000 Prospect C5 2 Probability of Success Table 2-4: C6000 Prospect C6 1 Probability of Success Table 2-5: C6000 Prospect C6 2 Probability of Success Table 2-6: C7000 Prospect C7 1 Probability of Success Table 2-7: C7000 Prospect C7 2 Probability of Success Table 2-8: E1000 Prospect E1 2 Probability of Success Table 2-9: E1000 Prospect E1 3 Probability of Success Table 2-10: E1000 Prospect E1 4 Probability of Success Table 3-1: Otakikpo area Original permeability ranges from Shell Table 3-2: Otakikpo - Reservoir parameters from Shell s petrophysical analysis Table 3-3: Otakikpo Shell s sums and averages over oil and gas pay zones Table 4-1: Otakikpo Reservoir Property ranges (Oil) Table 4-2 Otakikpo Reservoir Property ranges (Gas) Table 4-3: C5000 STOIIP Table 4-4: C5000 GIIP Table 4-5: C6000 STOIIP vi

9 Table 4-6: C7000 STOIIP Table 4-7: E1000 STOIIP Table 4-8 STOIIP and GIIP Summary by reservoir Table 4-9: C5000 STOIIP Table 4-10: C6000 STOIIP Table 4-11: C7000 STOIIP Table 4-12: E1000 STOIIP Table 4-13: Prospect 1 STOIIP Table 4-14: Prospect 2 STOIIP Table 4-15: Prospect 3 STOIIP Table 4-16: Prospect 4 STOIIP Table 5-1: Otakikpo RFT sample parameters Table 5-2: Model input parameters (P50 values) Table 5-3: Initial pressures and contact depths Table 5-4: Summary of initial Sw assumed for key reservoirs Table 5-5: Rel-perm values and end points Table 5-6: Otakikpo - Model layer scheme Table 5-7: E Summary of models runs with sensitivities of recovery vs. well numbers Table 5-8: Otakikpo Well schedule Table 5-9: Otakikpo - Monte Carlo results to determine ultimate recovery Table 5-10: Otakikpo - Recoveries for the P50 case Table 5-11: Otakikpo Oil prod. profiles P90-P50-P10 cases (100%) Table 6-1: Res. engineering inputs for P90-P50-P10 dev. scenarios Table 6-2: Overview of AGR TRACS cost estimates for P90 Case Table 6-3: Overview of AGR TRACS cost estimates for P50 Case with vertical wells Table 6-4: Overview of AGR TRACS cost estimates for P10 Case Table 6-5: Overview of capex phasing for P90-P50-P10 cases Table 6-6: Opex assumptions for notional Otakikpo development cases vii

10 Table 7-1: Otakikpo Econ. results NPV(0%) for P90-P50-P10 cases net to Lekoil Limited 60 Table 7-2: Otakikpo Econ. results NPV(10%) for P90-P50-P10 cases net to Lekoil Limited Table 7-3: Otakikpo Econ. results NPV(15%) for P90-P50-P10 cases net to Lekoil Limited Table 7-4: Otakikpo Econ. results NPV(20%) for P90-P50-P10 cases net to Lekoil Limited Table 8-1: Otakikpo Lekoil net P90-P50-P10 Unrisked Contingent Resources Table 8-2: AIM table of Otakikpo OML 11 Reserves; gross and net attributable to Lekoil Table 8-3: AIM table of Otakikpo OML 11 Contingent Resources; gross and net attributable to Lekoil Table 8-4: AIM table of Otakikpo OML 11 Contingent Resources net attributable to Lekoil; unrisked and risked Table 8-5: AIM table of Otakikpo OML 11 Unrisked Prospective Resources; gross and net attributable to Lekoil Table 9-1: Otakikpo OML 11 Unrisked and Risked Contingent Resources net attributable to Lekoil Table 9-2: Otakikpo P90-P50-P10 cases - Economic results NPV(10%), unrisked net to Lekoil Limited viii

11 Cover Letter Attn.: Lekan Akinyanmi/Dotun Adejuyigbe Lekoil Limited c/o Intertrust Corporate services (Cayman) limited 190 Elgin Avenue George Town Grand Cayman KY Cayman Islands 23 rd Gentlemen, Competent Person s Report on Otakikpo Marginal Field, OML 11, Nigeria In response to your request ( AGR TRACS ) has carried out a comprehensive review of the subsurface data provided by Lekoil Limited 1 on the Otakikpo Marginal Field in OML 11. Lekoil Oil and Gas Investments Limited ( Lekoil Oil and Gas ) 2 executed a farm-in agreement with the current licence holder Green Energy International Ltd ( Green Energy ) to acquire a 40% interest in Otakikpo, effective 17 th May Lekoil Limited ( Lekoil ) holds a 90% economic interest in Lekoil Nigeria Limited (with the remainder held by other minority interests), thus the valuations and attributable resource volumes presented in this report are for Lekoil s 36% interest in the Otakikpo Marginal Field. The seismic and map information provided was of varied quality for the main reservoirs due to the seismic database comprising only 2D data of mixed vintages from the period The log data from the three wells drilled in the early 1980 s (Otakikpo-001, -002 and -003) was of good quality, and supported by two MDT reports and fluid analyses. No test data was available, thus Lekoil provided representative ranges for reservoir permeability from analogue wells in the area. The initial work programme planned for late 2014 to early 2015 will focus on two of the existing wells, with recompletions in the C6000 and E1000 reservoirs in the 002 well, and recompletions in the C5000 and E1000 reservoirs in the 003 well. A full-field development will follow in the period with a further 7 wells planned (five vertical and two S- shaped wells, starting in Q4/2016), four of which are dual completions. This development scheme is not finalised, but AGR TRACS has developed independent cost estimates for the wells, onshore facilities and evacuation scheme as outlined by Lekoil in mid-july There is no approved development plan at present, hence the volumes assumed to be recovered through the initial recompletions and the subsequent development scheme have been classified as Contingent Resources with a Chance Of Commercial Success (COCS) of 70%. The Contingent Resource estimates have been derived using an economic model provided by Lekoil and reviewed by AGR TRACS. This is considered to correctly represent the Marginal Field Terms applicable to Otakikpo Lekoil Limited is registered in the Cayman Islands; it holds 90% of the economic interest in Lekoil Nigeria Limited, herein after referred to as Lekoil Nigeria. 2 Lekoil Oil and Gas is a wholly owned entity of Lekoil Nigeria. ix

12 The net attributable volumes quoted in this report reflect the farm-in terms agreed with Green Energy in May 2014 in order to transfer a 40% equity interest in the Otakikpo Marginal Field in OML 11 to Lekoil Oil and Gas, with 90% of this interest attributable to Lekoil Limited. The completion of the transfer requires a formal approval from the Minister of Petroleum Resources. However, Lekoil Oil and Gas and Green Energy have executed a Financial and Technical Services Agreement (FTSA) whereby Lekoil Oil and Gas is entitled to a 40% economic interest in the Otakikpo Marginal Field. Under the terms of the farm-in agreement, Lekoil Oil and Gas will carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy s share of the initial work program is reflected in Lekoil s share of project NPV. Following the review, AGR TRACS can report that the net unrisked 1C-2C-3C (P90-P50-P10) Contingent Resources at $80/bbl attributable to Lekoil (effective from late 2014) are estimated to be MMbbls, see Table 0-1. The corresponding net risked 1C-2C-3C (P90-P50-P10) contingent resources at $80/bbl attributable to Lekoil are estimated at MMbbls oil, see Table 0-2 below. Four exploration prospects have been identified. P90-P50-P10 STOIIP ranges have been estimated for these structures, however, insufficient data was available to enable economic evaluations to be carried out, thus no Prospective Resources can be estimated. Oil MMbbls Gross (from ) Net Attributable to Lekoil Limited (from ) Risk Factor Operator 1C Low Estimate 2C Best Estimate 3C High Estimate 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) Contingent Otakikpo % Green Energy Table 0-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil Oil MMbbls Unrisked Contingent Resources Net Attributable to Lekoil Limited Risk Factor Risked Contingent Resources Net Attributable to Lekoil Limited 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) 1C Low Estimate 2C Best Estimate 3C High Estimate Contingent Otakikpo % Table 0-2: Otakikpo Unrisked and Risked Contingent Resources and net attributable to Lekoil Economic evaluations have been carried out under $80-$100-$120/bbl oil price scenarios for the P90-P50-P10 cases with deviated wells from until end of economic life. The NPV(10%) MOD results of the economic evaluations indicate that the planned development of the Otakikpo Marginal Field is a robust project under all three oil price scenarios (see Table 0-3 for the NPV(10%) results. x

13 Otakikpo Case Cont. $80/bbl (MMbbls) NPV(10%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table 0-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited Exploration potential In addition to the Otakikpo discovery, four undrilled exploration prospects have been identified during the review of the 2D seismic data, as listed in Table 0-4 below. Prospects 1 and 2 have potential stacked reservoirs, while Prospects 3 and 4 are restricted to the deeper E1000 horizon. Due to the lack of detailed technical data, only total STOIIP and associated risk factors ( POS ) have been estimated. Lekoil s share would be 36% of the stated STOIIPs. Prospect Prospect 1 Prospect 2 Reservoir POS (%) Unrisked 100% STOIIP (MMbls) P90 P50 P10 C C C TOTAL* C C C E TOTAL* Prospect 3 E TOTAL Prospect 4 E TOTAL Table 0-4: Otakikpo exploration potential - Summary of 100% Unrisked STOIIPs * Note: Totals are arithmetic summations The work was undertaken by a team of AGR TRACS professional petroleum engineers and geoscientists based on data supplied by Lekoil. The data comprised details of licence and acreage interests, basic exploration geological and geophysical data, interpreted data, technical presentations, and Lekoil s seismic interpretations. AGR TRACS has not independently checked title interests with Government or licence authorities. xi

14 In estimating prospective and contingent resources we have used the standard petroleum engineering techniques. These estimates are based on the joint definitions of the Society of Petroleum Engineer, the World Petroleum Congress, the American Association of Petroleum Geologists and the 2007 PRMS (Petroleum Resources Management System). AGR TRACS has not conducted a site visit to independently verify the existence of physical assets. Qualifications is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report. The project was managed and signed off by Nigel Blott (M.Eng.), an AGR TRACS Manager. Mr. Blott, a petroleum engineer and SPE Member, has 30+ years experience from the Middle East, South-East Asia, and NW Europe. has conducted valuations for many energy companies and financial institutions. Basis of Opinion The evaluation presented in this report reflects our informed judgement based on accepted standards of professional investigation, but is subject to generally recognised uncertainties associated with the interpretation of geological, geophysical and subsurface reservoir data. It should be understood that any evaluation, particularly one involving exploration and future petroleum developments, may be subject to significant variations over short periods of time as new information becomes available. Yours faithfully, Nigel Blott xii

15 Disclaimer COMPETENT PERSON S REPORT ON LEKOIL LIMITED s 36% FARM-IN INTEREST IN THE OTAKIKPO MARGINAL FIELD, OML 11, NIGERIA This report relates specifically and solely to the subject petroleum licence interests and is conditional upon the assumptions made therein. This report must therefore be read in its entirety. This report was prepared in accordance with standard geological and engineering methods generally accepted by the oil and gas industry. Estimates of prospective hydrocarbon resources should be regarded only as estimates that may change as additional information become available. Not only are these estimates based on the information currently available, but are also subject to uncertainties inherent in the application of judgemental factors in interpreting such information. shall have no liability arising out of, or related to, the use of the report. 23 rd xiii

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17 Executive Summary The Otakikpo Marginal Field in OML 11, onshore Nigeria, was farmed out by the SPDC JV (NNPC/Shell/Total/Agip) to Green Energy International Limited (with approval by the Minister of Petroleum Resources) in January Lekoil Oil and Gas executed a farm-in agreement with the current licence holder Green Energy International Ltd ( Green Energy ) to acquire a 40% interest in Otakikpo, effective 17 th May 2014, and expects to commence the first phase of development work in late Lekoil Oil and Gas is wholly owned by Lekoil Nigeria; while Lekoil Limited ( Lekoil ) holds a 90% interest in Lekoil Nigeria (with the remainder held by other minority interests), thus the valuations and attributable resource volumes presented in this report are for Lekoil s 36% interest in the Otakikpo Marginal Field. AGR TRACS has carried out a comprehensive review of the surface and subsurface data provided by Lekoil from the Otakikpo field. The seismic and map information provided was of varied quality for the main reservoirs due to the seismic database comprising only 2D data of mixed vintages from the period The log data from the three wells drilled in the early 1980 s (Otakikpo-001, -002 and -003) was of good quality, and supported by two MDT reports and fluid analyses. No test data was available, thus Lekoil provided representative ranges for reservoir permeability from analogue wells in the area. The initial work programme planned for late 2014 to early 2015 will focus on two of the existing wells, with recompletions in the C6000 and E1000 reservoirs in the 002 well, and recompletions in the C5000 and E1000 reservoirs in the 003 well. A full-field development will follow in the period with a further 7 wells planned (five vertical and two S- shaped wells, starting in Q4/2016), four of which are dual completions. This development scheme is not finalised, but AGR TRACS has developed independent cost estimates for the wells, onshore facilities and evacuation scheme as outlined by Lekoil in mid-july There is no approved development plan at present, hence the volumes assumed to be recovered through the initial recompletions and the subsequent development scheme have been classified as Contingent Resources with a Chance Of Commercial Success (COCS) of 70%. The Contingent Resource estimates have been derived using an economic model provided by Lekoil and reviewed by AGR TRACS. This is considered to correctly represent the Marginal Field Terms applicable to Otakikpo. The net attributable volumes quoted in this report reflect the farm-in terms agreed with Green Energy in May 2014 in order to transfer a 40% equity interest in the Otakikpo Marginal Field in OML 11 to Lekoil Oil and Gas, with 90% of this interest attributable to Lekoil Limited. The completion of the transfer requires a formal approval from the Minister of Petroleum Resources. However, Lekoil Oil and Gas and Green Energy have executed a Financial and Technical Services Agreement (FTSA) whereby Lekoil Oil and Gas is entitled to a 40% economic interest in the Otakikpo Marginal Field. Under the terms of the farm-in agreement, Lekoil Oil and Gas will carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy s share of the initial work program is reflected in Lekoil s share of project NPV. Following the review, AGR TRACS can report that the net unrisked 1C-2C-3C (P90-P50-P10) Contingent Resources at $80/bbl attributable to Lekoil (effective from late 2014) are estimated to be MMbbls, see Table ES-1. The corresponding net risked 1C-2C-3C (P90-P50-P10) contingent resources at $80/bbl attributable to Lekoil are estimated at MMbbls oil, see Table ES-2 below. xv

18 Four exploration prospects have been identified. P90-P50-P10 STOIIP ranges have been estimated for these structures, however, insufficient data was available to enable economic evaluations to be carried out, thus no Prospective Resources can be estimated. Oil MMbbls Gross (from ) Net Attributable to Lekoil Limited (from ) Risk Factor Operator 1C Low Estimate 2C Best Estimate 3C High Estimate 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) Contingent Otakikpo % Green Energy Table ES-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil Oil MMbbls Unrisked Contingent Resources Net Attributable to Lekoil Limited Risk Factor Risked Contingent Resources Net Attributable to Lekoil Limited 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) 1C Low Estimate 2C Best Estimate 3C High Estimate Contingent Otakikpo % Table ES-2: Otakikpo Unrisked and Risked Contingent Resources net attributable to Lekoil Economic evaluations have been carried out under $80-$100-$120/bbl oil price scenarios for the P90-P50-P10 cases from until the end of the economic life of the field. The NPV(10%) MOD results of the economic evaluations indicate that the planned development of the Otakikpo Marginal Field is a robust project under all three oil price scenarios (see Table ES-3 for the NPV(10%) results). Otakikpo Case Cont. $80/bbl (MMbbls) NPV(10%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table ES-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited xvi

19 1. Introduction On 21 st January 2014, the Minister of Petroleum approved the farmout of the Otakikpo Marginal Field by Shell Petroleum Development Company ( SPDC, 30%), Total E&P Nigeria Limited ( TEPNG, 10%), and Nigerian Agip Oil Company Limited ( NAOC, 5%) and Nigerian National Petroleum Corporation ( NNPC, 55%) (jointly the SPDC JV ) to Green Energy International Limited ( Green Energy ). Otakikpo was discovered in 1981 and is located within OML 11 close to the coast and some 32km east of the Bonny oil terminal, see Figure 1-1 and Figure 1-2. Figure 1-1: Location map Otakikpo Marginal Field, OML 11, Nigeria The area included in the farm-out is defined by four corner points (A-D) and measures approximately 6.6 x 8.3 km, or some 55 sq km, see Figure 1-3. The farm-out is restricted in depth to 11,807ft TVDss. There are no surface facilities within the Otakikpo Marginal Field area, but three wells were drilled in the period (Otakikpo-001, -002 and -003). The coordinates of the four corner points (A-D) shown in Figure 1-3 are as follows: Eastings Northings A mE mN B mE mN C mE mN D mE mN In May 2014 Lekoil announced they had farmed into Otakikpo, and this report provides an independent review of the field including estimates of net unrisked and risked Contingent Resources attributable to Lekoil. 1

20 Figure 1-2: Otakikpo field location within Niger Delta Figure 1-3: Otakikpo farm-out area, OML 11 2

21 2. Geoscience Review The objective of this review was to evaluate the four reservoirs that have been discovered by the Otakikpo-002 and Otakikpo-003 wells. These are the C5000, C6000, C7000 and E1000 reservoirs. The Otakikpo-001 well failed to encounter any hydrocarbons due to the absence of the reservoir. Exploration prospects were also identified and briefly reviewed. Figure 2-1 shows the location of the field, the Otakikpo farm-out area, and the surrounding blocks. The Otakikpo farm-out area lies within OML 11. Figure 2-1: Location map The aim of this section is to summarise the geoscience data provided for OML 11 and assess the volumetric potential of the Otakikpo discovery Data available The primary source of data was a Petrel project which contained 2D seismic lines, well data and interpreted horizons. These data were exported and used to create a Kingdom seismic project where the evaluation was conducted. 3

22 The seismic dataset consists of 18 2D lines, 12 of which are dip lines with a north south orientation, four are strike lines with an approximately west east orientation and one line has a northwest southeast direction. It is not clear when the seismic data was acquired but based on the line numbering it is assumed that acquisition occurred at various times between 1967 and There are no details on the acquisition or processing parameters. It is not known if the data provided is the originally processed data or more recently re-processed versions. In any event, the data quality is fair to poor. The well data consists of limited log data and in the case of the Otakikpo-001 well, no Sonic data was available to generate a synthetic. It was possible to create synthetics for the Otakikpo-002 and Otakikpo-003 wells and reasonable ties to the seismic were possible. Formation tops were provided and were found to be a good representation of the reservoir units in the Otakikpo-002 and Otakikpo-003 wells. The lack of reservoir in the Otakikpo-001 well makes correlation very difficult and the tops are considered unreliable in most cases. Note that Lekoil are planning to acquire a 3D survey over the field, most likely in early 2016 prior to the main phase of development drilling Seismic Interpretation The fault and horizon interpretation provided by Lekoil was reviewed and although in part provided a useful framework, due to the poor quality of the data it was found that there were some inconsistencies that needed to be assessed. It was therefore decided to carry out an independent interpretation to provide an alternative view of the structures. Four horizons were interpreted corresponding to the four reservoirs discovered in the wells. Figure 2-2 shows a north south line through the Otakikpo-002 well and the interpreted reflectors. 4

23 AGR TRACS CPR on Otakikpo for Lekoil Figure 2-2: Line showing well ties The following sections summarise the results of this interpretation C5000 The C5000 horizon is the shallowest of the reservoirs encountered and is interpreted as a peak on the seismic data (Figure 2-2 above). A number of significant faults have been interpreted and these appear to have a dominant west east trend. The northern faults are major features that down throw to the south. The faults further to the south are antithetic with throws to the north. The Otakikpo-002 and Otakikpo-003 wells both encountered oil in the C5000 reservoir. However, the Otakikpo-002 well also discovered a gas cap which was not seen in the Otakikpo-003 well. It is therefore interpreted that the two wells are in separate compartments. 5

24 The C5000 horizon was interpreted on all of the 2D seismic lines although the six lines in the southern part of the area were difficult to include as they do not intersect with any of the other lines available so ensuring the correct reflector is correlated is problematic. A reasonable correlation was made across the gap between the lines to the north and the southern lines but this is an area of uncertainty that will remain until additional seismic data is acquired to tie this area properly. The faults were correlated and a general west east trend was established. The horizon was gridded to generate a Two-Way Time (TWT) structure map which is shown in Figure 2-3 below. The faults provide the mechanism required to separate the Otakikpo-002 and Otakikpo-003 wells. Figure 2-3: C5000 Two-Way Time map The TWT map shows the Otakikpo wells to be on a relative structural high with the Otakikpo-002 well in a separate fault compartment to the Otakikpo-003 well. The surface dips to the south as seen on the seismic data C6000 The C6000 horizon has been picked as a trough on the seismic data which, at the Otakikpo-002 well and to the north of the Otakikpo-003 well has a reasonably high amplitude. Away from the wells it is a poorer quality event and so is more difficult to 6

25 AGR TRACS CPR on Otakikpo for Lekoil correlate around the lines. However, it is close to the C5000 reflector which was used as a guide to interpreting the C6000 horizon. As with the C5000 horizon, correlating the C6000 event onto the southern lines is difficult and in this area the interpretation has some uncertainty. However, based on the resulting TWT map which shows a smooth transition across this area, it is considered that this interpretation provides a good representation of the C6000 surface. Figure 2-4 shows a north south line close to the Otakikpo-003 well showing the high amplitude features to the north of the well. This anomaly may be indicative of the presence of hydrocarbons although with only 2D seismic data available, the extent of this anomaly cannot be fully defined. Figure 2-4: Line showing amplitude anomaly At this level, only the Otakikpo-002 well found hydrocarbons although the depths to the top of the C6000 sand are similar in both the Otakikpo-002 well and the Otakikpo-003 well. It appears that the fault between the two penetration points is again having an influence on the fluid distribution. 7

26 The interpreted horizon was gridded and the resulting TWT structure map is shown in Figure 2-5 below. Figure 2-5: C6000 Two-Way Time map The TWT map shows a similar trend to the C5000 map with the Otakikpo-002 and Otakikpo- 003 wells in separate compartments C7000 The C7000 event was picked as a trough. At the Otakikpo-002 and north of the Otakikpo- 003 well the amplitude is relatively bright. It is less bright at the Otakikpo-003 location and it is possible that the amplitude is providing some indication of the presence of hydrocarbons as no oil was encountered at the Otakikpo-003 location. With 2D data this is difficult to quantify but 3D may provide a better correlation. The lines to the south which have no direct intersections with the lines to the north have again been jump correlated. The resulting map shows a smooth transition across the gap between the two sets of lines. The C7000 interpretation was gridded and the resulting TWT map is shown in Figure 2-6 below. 8

27 Figure 2-6: C7000 Two-Way Time map The penetration point of the Otakikpo-003 well is interpreted to be to the south of the west-east trending fault which provides an explanation for the lack of hydrocarbons in the Otakikpo-003 well E1000 The E1000 horizon is the deepest of the reservoirs intersected. It has been interpreted as a peak above a relatively bright peak / trough doublet. At this level, it appears that the Otakikpo-003 well intersects the E1000 horizon to the north of the west east fault. This well encountered oil as did the Otakikpo-002 well. The Oil Water Contact is slightly different in the two wells although the Otakikpo-003 well is significantly deviated so it is possible that there is an error with the deviation such that the contacts could be the same in both wells. For the purpose of this evaluation, it has been assumed that the contact is the same and the deeper contact has been used. There is a small closure to the south of the fault so if the well positioning is in error there may be some potential to the south of the fault although it is a small volume. The gridded E1000 horizon is shown in Figure 2-7 below. 9

28 Figure 2-7: E1000 Two-Way Time map The E1000 interpretation suffers the same problem with the lines to the south as the other horizons do but as in the other cases, the correlation across the gap seems reasonable as shown by the smooth contours on the TWT map. At this level, the Otakikpo-003 well is interpreted as having crossed the west east fault and penetrates the E1000 horizon to the north of the fault. This may be the reason that oil was encountered in both this well and the Otakikpo-002 well. It also leaves open the opportunity for a hydrocarbon accumulation to the south of the fault as detailed in Section below Depth Conversion and Depth maps In order to depth convert the TWT grids, a simple velocity model has been used. With only three wells available (and when one of those has significant uncertainty particularly in the placement of the tops), the scope for velocity analysis is limited. Simple average interval velocities were used for each layer although a simple function was found to give good results for the E1000 surface. The table below shows the well misties, in feet, using this method. 10

29 Horizon Otakikpo-001 Otakikpo-002 Otakikpo-003 C C C7000 Poor Tie E Table 2-1: Well to Grid misties (-ve value means grid is deeper than the well) The depth values in the Otakikpo-001 well are unreliable given that there is no reservoir present and so correlating the age equivalent interval is difficult. Previous evaluations by other companies, including Shell, have tended to exclude the tops from this well and no significant effort has been made to tie the tops from this well in this evaluation. The following sections summarise the depth conversion approach used and shows the resulting depth maps for each horizon C5000 To create a depth map for the C5000 horizon, an average interval velocity of 7,520 ft/sec from sea bed to C5000 was applied. The resulting depth map is shown in Figure 2-8 below. Figure 2-8: C5000 Depth structure map 11

30 The resulting map ties the wells closely and the closing contours agree with the various contacts seen in the wells. No significant editing was required to achieve this. The depth errors at the wells are small for this horizon as seen in Table 2-1 above C6000 The C6000 depth map is the result of using an average interval velocity of 7,300 ft/sec for the C5000 to C6000 interval. This velocity was applied to the C5000 to C6000 isochron and the resulting isopach was added to the C5000 depth map to give the C6000 depth map which is shown Figure 2-9 below. Figure 2-9: C6000 Depth structure map The well misties at this level are well within an acceptable range and again, no significant editing of the time interpretation was required to tie the contact data seen in the wells. The well misties for this surface are shown in Table 2-1 above C7000 The C6000 to C7000 interval was used to generate the C7000 depth map. An interval velocity of 14,250 ft/sec was applied to the isochron wich resulted in a C6000 to C

31 isopach. This was added to the C6000 depth map resulting in the C7000 depth map shown in Figure Figure 2-10: C7000 Depth structure map The depth map is in close agreement with the well hydrocarbon contacts again without the need for any editing. The well misties are shown in Table 2-1 above. The Otakikpo-001 well is a poor tie and this may be due to a mis-correlation of the horizon top E1000 To depth convert to the E1000 surface a simple Time / Velocity function from sea bed to E1000 was used as this resulted in the smallest misties at the wells. Figure 2-11 below shows the function used. 13

32 8400 Sea Floor to E1000 Interval Velocity (ft/sec) y = x R² = Isochron (ms) Figure 2-11: Sea Floor to E1000 Velocity Function The velocity grid derived from this function was applied to the time grid to generate a depth map shown in Figure 2-12 below which agreed with the contacts seen in the wells. Figure 2-12: E1000 Depth structure map 14

33 2.4. Prospects During the course of the interpretation and mapping of the Otakikpo area, a number of prospects have been identified at each of the reservoir levels. These will be summarised in the following sections together with an estimate of the hydrocarbons in place and an assessment of the exploration risk C5000 Prospects Two areas of closure have been mapped at the C5000 level; one to the north of the Otakikpo-001 well and one south west of the Otakikpo-003 well. Figure 2-13 shows the location of these prospects. Figure 2-13: C5000 Prospect locations The Probability of Success (POS) for the two C5000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. C5000 Prospect 1 is located approximately 400m north west of the Otakikpo-001 well and 1.7km north west of the Otakikpo-002 well. The Otakikpo-002 well has proven the presence of a working hydrocarbon system in the area. However, the lack of reservoir encountered in the nearer Otakikpo-001 well increases the risk for Prospect C5 1. Prospect C5 2 is located approximately 4km south west of the Otakikpo-003 penetration point. The presence of reservoir and hydrocarbons in the Otakikpo-003 well reduce the risk for Prospect C

34 The parameters and overall probability of success estimated for C5000 Prospect C5 1 and Prospect C5 2 are given in Table 2-2 and Table 2-3 below: Parameter POS Comments Source 0.8 Source proven to south. Slight risk of oil migration shadow. Seal 0.8 Low risk. Slight risk of cross fault leakage. Reservoir 0.5 High risk of reservoir presence, due to absence in Otakikpo Trap 0.7 Four lines define the trap. Risk due to 2D data Overall % Chance of Success (or approximately 1 in 4.5) Table 2-2: C5000 Prospect C5 1 Probability of Success Parameter POS Comments Source 0.8 Source proven to in Otakikpo-003. Slight risk of oil migration shadow. Seal 0.8 Low risk. Slight risk of cross fault leakage. Reservoir 0.7 Trap 0.6 Reservoir present in Otakikpo-003. Reservoir presence probable. Only two lines define trap and close to edge of data so trap may not be present as mapped. Overall % Chance of Success (or approximately 1 in 3.7) Table 2-3: C5000 Prospect C5 2 Probability of Success C6000 Prospects Two prospects have been mapped at the C6000 level; Prospect C6 1 is to the north of the Otakikpo-001 well and Prospect 2 is south west of the Otakikpo-003 well. Figure 2-14 shows the location of these prospects. The Probability of Success (POS) for the C6000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. C6000 Prospect C6 1 is mapped approximately 400m north west of the Otakikpo-001 well and 1.7km north west of the Otakikpo-002 well. The Otakikpo-002 well has proven the presence of a working hydrocarbon system although the lack of reservoir in the nearby Otakikpo-001 well results in an increased risk for Prospect C6 1. Prospect C6 2 is located approximately 4km south west of the Otakikpo-003 well. The presence of reservoir in the Otakikpo-003 well reduces the Reservoir risk for Prospect C6 2. However, the lack of hydrocarbons in the Otakikpo-003 well increases the Source risk. 16

35 Figure 2-14: C6000 Prospect locations The parameters and overall probability of success estimated for C6000 Prospect C6 1 and Prospect C6 2 are given in Table 2-4 and Table 2-5 below: Parameter POS Comments Source 0.8 Source proven in Otakikpo-002. Slight risk of oil migration shadow. Seal 0.6 Trap relies on two faults increasing the risk. Reservoir 0.5 High risk of reservoir presence, due to absence in Otakikpo Trap 0.7 Four lines define the trap. Risk due to 2D data Overall % Chance of Success (or approximately 1 in 6) Table 2-4: C6000 Prospect C6 1 Probability of Success 17

36 Parameter POS Comments Source 0.7 Source proven in Otakikpo-002. Absence of hydrocarbons in Otakikpo-003 increases risk. Seal 0.8 Low risk. Slight risk of cross fault leakage. Reservoir 0.7 Trap 0.6 Reservoir present in Otakikpo-003. Reservoir presence probable. Only two lines define trap and close to edge of data so trap may not be present as mapped. Overall % Chance of Success (or approximately 1 in 4.25) Table 2-5: C6000 Prospect C6 2 Probability of Success C7000 Prospects Two prospects have been identified at the C7000 level; Prospect C7 1 is a closure to the north of the Otakikpo-001 well and Prospect C7 2 is located south west of the Otakikpo-003 well. Figure 2-15 shows the location of these prospects. Figure 2-15: C7000 Prospect locations The Probability of Success (POS) for the C7000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. C7000 Prospect C7 1 is located approximately 800m north west of the Otakikpo-001 well and 1.6km north west of the Otakikpo-002 well. 18

37 The Otakikpo-002 well has proven the presence of a working hydrocarbon system although the lack of reservoir in the nearby Otakikpo-001 well increases the overall risk for Prospect C7 1. Prospect C7 2 is located approximately 4.2km south west of the Otakikpo-003 well. As with the C6000 prospects, the presence of reservoir sands in the Otakikpo-003 well reduces the Reservoir risk for Prospect C7 2. However, the absence of oil in the Otakikpo-003 well increases the Source risk. The parameters and overall probability of success estimated for C7000 Prospect C7 1 and Prospect C7 2 are given in Table 2-6 and Table 2-7 below: Parameter POS Comments Source 0.8 Source proven in Otakikpo-002. Slight risk of oil migration shadow. Seal 0.6 Trap relies on two faults increasing the risk. Reservoir 0.5 High risk of reservoir presence, due to absence in Otakikpo Trap 0.7 Four lines define the trap. Risk due to 2D data Overall % Chance of Success (or approximately 1 in 6) Table 2-6: C7000 Prospect C7 1 Probability of Success Parameter POS Comments Source 0.7 Source proven to in Otakikpo-002. Absence of hydrocarbons in Otakikpo-003 increases risk. Seal 0.8 Low risk. Slight risk of cross fault leakage. Reservoir 0.7 Trap 0.6 Reservoir present in Otakikpo-003. Reservoir presence Probable. Only two lines define trap and close to edge of data so trap may not be present as mapped. Overall % Chance of Success (or approximately 1 in 4.25) Table 2-7: C7000 Prospect C7 2 Probability of Success E1000 Prospects Three prospects have been mapped at the E1000 level; Prospect E1 2 is mapped south west of the Otakikpo-003 well. Prospect E1 3 is a closure south of the Otakikpo-003 penetration which at this level is interpreted as being north of the bounding fault. If it is shown that the Otakikpo-003 well actually penetrates the fault to the south, this prospect will become a discovery. Prospect E1 4 is located to the north of the Otakikpo-001 well. Figure 2-15 shows the location of these prospects. 19

38 Figure 2-16: E1000 Prospect locations The Probability of Success (POS) for the C7000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. Prospect 2 is located approximately 4.5km south west of the Otakikpo-003 well. As with the C6000 prospects, the presence of reservoir sands in the Otakikpo-003 well reduces the Reservoir risk for Prospect E1 2. The presence of oil in the Otakikpo-003 well also improves the Source risk although the fact that the Otakikpo-003 well appears to penetrate the E1000 reservoir to the north of the bounding fault does mean that some risk remains. The lack of hydrocarbons in the overlying reservoirs on the south side of the fault increases the Source risk. Prospect 3 is located immediately south of the Otakikpo-003 well and assumes that the Otakikpo-003 well intersected the E1000 reservoir to the north of the west east bounding fault. If this is not the case or if there is cross fault leakage the structure will no longer be classified as a prospect as the Otakikpo-003 well encountered oil at this level. It will limit the closure, however, as this well penetrated an OWC at approximately 10,729ft. The maximum closure as currently mapped is at 11,250ft so the potential STOIIP will be significantly reduced. C7000 Prospect E1 4 is mapped approximately 1.2km north west of the Otakikpo-001 well and 2.1km north west of the Otakikpo-002 well. The Otakikpo-002 well has proven the presence of a working hydrocarbon system although the failure to encounter reservoir in the nearby Otakikpo-001 well increases the overall risk for Prospect E1 4. The parameters and overall probability of success estimated for E1000 Prospect E1 2, Prospect E1 3 and Prospect E1 4 are given in Table 2-10, Table 2-8 and Table 2-9 below: 20

39 Parameter POS Comments Source 0.7 Source proven to in Otakikpo-002. Absence of hydrocarbons in Otakikpo-003 increases risk. Seal 0.8 Low risk. Slight risk of cross fault leakage. Reservoir 0.7 Trap 0.6 Reservoir present in Otakikpo-003. Reservoir presence Probable. Only two lines define trap and close to edge of data so trap may not be present as mapped. Overall % Chance of Success (or approximately 1 in 4.25) Table 2-8: E1000 Prospect E1 2 Probability of Success Parameter POS Comments Source 0.5 No hydrocarbons in the shallower reservoirs in this location. High risk. Seal 0.7 Risk of cross fault leakage which would reduce closure. Reservoir 0.8 Reservoir present in Otakikpo-003 and to the north. Trap 0.7 Four lines define trap although one line is at the edge of the structure and one is a strike line. Overall % Chance of Success (or approximately 1 in 5.1) Table 2-9: E1000 Prospect E1 3 Probability of Success Parameter POS Comments Source 0.8 Source proven in Otakikpo-002. Slight risk of oil migration shadow. Seal 0.6 Risk of cross fault leakage. Reservoir 0.5 High risk of reservoir presence, due to absence in Otakikpo Trap 0.6 Only two lines define the trap. Risk due to 2D data Overall % Chance of Success (or approximately 1 in 6) Table 2-10: E1000 Prospect E1 4 Probability of Success Estimates of Stock Tank Oil Initially In Place(STOIIP) and Gas Initially In Place (GIIP) have been made for the discovered structures and the prospects. A summary of the input parameters and the resulting volumes is provided in Section 4.0 below. 21

40 3. Otakikpo Petrophysics Review The Otakikpo field contains three wells that penetrate the main zones of interest. The digital data provided for all three wells comprises the standard logs required for petrophysical analysis, while additional files made available include the comprehensive set of sums and averages. Overall the reservoir section is built up of a series of stacked channels each containing good reservoir quality sands. In total 4 zones contain hydrocarbons in both Otakikpo 002 and Otakikpo 003. However, Otakikpo 001 contains no well-developed reservoir sections, and is not included in the petrophysical analysis. No information was available to allow a specific permeability range to be established. Lekoil supplied a table from an original Shell study showing permeability ranges (see Table 3-1 below), but no source information. As no provenance is available for the ranges suggested, comparisons with analogue data that contains core indicate the ranges to be acceptable, and these have therefore been used for the reservoir simulation work. Suggested permeability ranges for Otakikpo from Shell (md) Reservoir P85 P50 P15 C C C E Table 3-1: Otakikpo area Original permeability ranges from Shell (Source: Lekoil, July 2014) 3.1. AGR TRACS quick-look petrophysical review No detailed petrophysical curves were supplied, thus AGR TRACS calculated a set of quick look curves to QC the overall sums and averages supplied. The C5000 is a thin sand with a substantial shale baffle towards the middle (Figure 3-1). In Otakikpo 002 the hydrocarbon phase is predominantly gas overlying a thin oil rim, while in Otakikpo 003 the C5000 is entirely oil-bearing. Net to gross values are around 0.75 for both wells, while porosities are good at The hydrocarbon saturations are moderate, being 0.7 for gas and 0.5 for oil. 22

41 Figure 3-1: CPI plot of C5000 reservoir in Otakikpo 002 The C6000 is a moderately thick sand with several shale baffles (Figure 3-2). As with C5000 the net to gross values are good at 0.8. The C6000 is only hydrocarbon-bearing in Otakikpo 002, while it is interpreted water-wet in Otakikpo 003. The porosities are slightly higher than seen in C5000 at around 0.25; this is possibly due to better channel development. Hydrocarbon saturations in Otakikpo 002 are excellent at 0.8. Figure 3-2: CPI plot of C6000 reservoir in Otakikpo

42 The C7000 is a thick moderately developed sand containing multiple thin shale streaks, but where sand is present it is of good quality (Figure 3-3). Net to gross values of 0.85 are averaged over the two wells. As with C6000 only Otakikpo 002 contains hydrocarbons, but restricted to the upper part of the interval. Porosities are quite variable between the wells; with Otakikpo 002 having an average of 0.21 while Otakikpo 003 has an average of Otakikpo 003 has the higher net to gross value of 0.9 indicating better sand development. The hydrocarbon saturations for Otakikpo 002 are good at 0.7. Figure 3-3: CPI plot of C7000 reservoir in Otakikpo 002 The E1000 interval comprises a series of stacked channels separated by significant shale barriers (). The sequence is very thick at around 250ft, and as such the shales only have a minor impact on net to gross which is good at 0.8. The porosities are moderate, and similarly as with the C7000 Otakikpo 003 has a better porosity average at 0.23 while Otakikpo 002 has an average of Both wells contain hydrocarbons, and both display a contact. Otakikpo 002 has a OWC 10,744ft Md while the deviated well Otakikpo 003 has a ODT at 11,659ft Md. The hydrocarbon saturations are good; averaging around 0.65, and there is a small effect of the transition zone reducing the average hydrocarbon saturation. 24

43 Figure 3-4: CPI plot of E1000 in Otakikpo Otakikpo sums and averages Comparisons between AGR TRACS quick look interpretation and the sums and averages provided by Lekoil s petrophysical studies are good. The AGR TRACS review tends to give a slightly higher porosity, and as a consequence a slightly lower Sh by pore volume. Given the quick look nature of the AGR TRACS study, it was decided to use the supplied sums and averages for our analysis (see Table 3-2 and Table 3-3 below). 25

44 Otakikpo Wells Interval (ft Md) Reservoir Rock Well Zones Top Bottom Gross Net Sand N/G POR_Res 002 C5000 8, , C5000 8, , C6000 8, , C6000 8, , C7000 8, , C7000 8, , E ,557 10, E ,626 10, Table 3-2: Otakikpo - Reservoir parameters from Shell s petrophysical analysis Otakikpo Wells GAS Pay OIL Pay Well Zones Gross Pay Net Pay N/G PORg Swg Gross Pay Net Pay N/G PORo Swo 002 C C C C C C E E Table 3-3: Otakikpo Shell s sums and averages over oil and gas pay zones 26

45 4. In-Place Volumetric Estimates To estimate the In-Place hydrocarbon volumes for the Otakikpo reservoirs, Gross Rock Volumes were calculated from Kingdom and input to the Monte Carlo Crystal Ball simulation. These were combined with ranges of reservoir properties resulting in a range of Stock Tank Oil Initially In Place (STOIIP) estimations. The following sections provide a summary of the inputs and results for the Otakikpo reservoirs Otakikpo HIIP estimates The Otakikpo structure consists of a number of reservoirs and volumes have been estimated for each. The reservoirs identified are; - C C C E Otakikpo Reservoir Property inputs Gross Rock Volumes (GRVs) were extracted from Kingdom and a range was established based on the presence or otherwise of a hydrocarbon contact and the closing contour of the structure. There is some uncertainty in the interpretation and depth conversion which has also been taken into account. However, the structures are relatively small and the difference between the Oil-Down-To (ODT) and the closing contour is small so the resulting range in GRV is quite narrow. The reservoir properties were derived from the well data and ranges were estimated based on the limits seen in the wells. The reservoirs are generally average to good quality and because of the number of wells, the ranges are relatively narrow. The table below (Table 4-1) lists the ranges of properties input to the Monte Carlo simulation. Reservoir C5000 well 002 C5000 Well 003 GRV (MMm3) NTG (Frac) Porosity (Frac) Sw (Frac) FVF (rb/stb) P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P C C E Table 4-1: Otakikpo Reservoir Property ranges (Oil) 27

46 Reservoir C5000 well 002 GRV (MMm3) NTG (Frac) Porosity (Frac) Sw (Frac) GEF (scf/ft 3 ) P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P Table 4-2 Otakikpo Reservoir Property ranges (Gas) C5000 Volumetric estimates Hydrocarbons have been discovered in the C5000 reservoir in both the Otakikpo-002 and the Otakikpo-003 wells. However, in the Otakikpo-002 well, a gas cap was also encountered so the two accumulations are interpreted as being separate. Figure 4-1 shows a map of the C5000 reservoir with the various contacts illustrated. In the Otakikpo-002 area, a Gas Oil Contact (GOC) has been identified at 8,296ft and this is used to restrict the GRV for the gas column. In the oil leg, an ODT was established at 8,320ft. This represents the minimum potential oil column and the closing contour (at 8,360ft) was used to define the upside. Figure 4-1: C5000 Reservoir depth map with contacts Using the input ranges provided in Table 4-1 and Table 4-2, the following hydrocarbon in place ranges were estimated (Table 4-3 and Table 4-4): 28

47 Reservoir STOIIP (MMbls) P90 P50 P10 C area C area TOTAL* Table 4-3: C5000 STOIIP Reservoir GIIP (bcf) P90 P50 P10 C area TOTAL* Table 4-4: C5000 GIIP * Note: Totals are arithmetic summations C6000 Volumetric estimates Hydrocarbons have been discovered in the C6000 reservoir but only in the Otakikpo-002 well. Figure 4-2 shows a map of the C6000 reservoir with the various contacts illustrated. Figure 4-2: C6000 Reservoir depth map with contacts 29

48 An ODT was picked in the Otakikpo-002 well at 8,491ft and this represents the minimum case. The closing contour at 8,502ft was used to constrain the upside. Using the input ranges provided in Table 4-1, the following hydrocarbon in place range was estimated (Table 4-5): Reservoir STOIIP (MMbls) P90 P50 P10 C Table 4-5: C6000 STOIIP C7000 Volumetric estimates Hydrocarbons have been discovered in the C7000 reservoir but only in the Otakikpo-002 well. Figure 4-2 shows a map of the C7000 reservoir with the various contacts illustrated. Figure 4-3: C7000 Reservoir depth map with contacts An Oil Water Contact (OWC) was picked in the Otakikpo-002 well at 8,718ft and this represents the maximum case. A range of GRV was established to account for uncertainty in the interpretation and the depth conversion. Using the input ranges provided in Table 4-1, the following hydrocarbon in place range was estimated (Table 4-6): 30

49 STOIIP (MMbls) Reservoir P90 P50 P10 C Table 4-6: C7000 STOIIP E1000 Volumetric estimates Hydrocarbons have been discovered in the E1000 reservoir in both the Otakikpo-002 and the Otakikpo-003 wells. It is not entirely clear whether the two wells are in the same compartment although based on the 2D seismic data, it would appear that they are. Figure 4-4 shows a map of the C5000 reservoir with the various contacts illustrated. Figure 4-4: E1000 Reservoir depth map with contacts An Oil Water Contact (OWC) was picked in both the Otakikpo-002 well at 10,713ft and the Otakikpo-003 well at 10,729ft. For the purpose of this evaluation, it has been assumed that the wells have a common contact and the discrepancy is due to the deviation of the Otakikpo-003 well and the inaccuracy of the deviation survey. The deeper value has been used in order to capture the full range and this represents the maximum case. A range of GRV was established to account for uncertainty in the interpretation and the depth conversion. Using the input ranges provided in Table 4-1, the following hydrocarbon in place range was estimated (Table 4-7): 31

50 STOIIP (MMbls) Reservoir P90 P50 P10 E Table 4-7: E1000 STOIIP STOIIP and GIIP Summary The following table (see Table 4-8) provides a summary of the STOIIP and GIIP estimates for the discovered reservoirs. Reservoir STOIIP (MMbls) GIIP (bcf) P90 P50 P10 P90 P50 P10 C area C area C C E TOTAL* Table 4-8 STOIIP and GIIP Summary by reservoir * Note: Totals are arithmetic summations 4.2. Otakikpo Prospect HIIP Estimates A number of prospects have been identified at the various reservoir intervals and HIIP estimates have been made for each prospect at each level. Gross Rock Volumes have been estimated and the reservoir properties provided in Table 4-1 above have been used. The following sections summarise the HIIP estimates for prospects at each reservoir level. The volumes quoted are unrisked. The Probability of Success (POS) estimates for each prospect can be found in Section 2.4 above C5000 Prospects. Two prospects have been identified at the C5000 level. The locations are shown in Figure 2-13 in Section 2 above. GRVs for the two prospects were calculated and combined with the properties in Table 4-1 resulting in the following range of hydrocarbon in place estimates (Table 4-9). 32

51 Reservoir STOIIP (MMbls) P90 P50 P10 C5000 Prospect C C5000 Prospect C TOTAL* Table 4-9: C5000 STOIIP * Note: Totals are arithmetic summations In each case the closing contour was used to estimate the GRV and this was varied by approximately +/- 30% to provide a range to account for uncertainties in the interpretation and depth conversion C6000 Prospects Two prospects have been mapped at the C6000 level. The locations are shown in Figure 2-14 in Section 2 above. Using the polygons shown in Figure 2-14, GRVs for the two prospects were calculated and combined with the properties in Table 4-1. The resulting hydrocarbon in place estimates are provided in Table 4-10 below. Reservoir STOIIP (MMbls) P90 P50 P10 C6000 Prospect C C6000 Prospect C TOTAL* Table 4-10: C6000 STOIIP * Note: Totals are arithmetic summations In both cases the closing contour was used to estimate the GRV. This was then varied by approximately +/- 30% to provide a range for input to the Monte Carlo and this accounts for uncertainties in the interpretation and depth conversion C7000 Prospect At the C7000 reservoir level, two prospects have been identified. Their locations are shown in Figure 2-15 in Section 2 above. Polygons were drawn to constrain the areas of the prospects and these are shown in Figure The GRVs for the two prospects were calculated and combined with the properties in Table 4-1. The resulting hydrocarbon in place estimates are shown in Table 4-11 below. 33

52 Reservoir STOIIP (MMbls) P90 P50 P10 C7000 Prospect C C7000 Prospect C TOTAL* * Note: Totals are arithmetic summations Table 4-11: C7000 STOIIP The closing contour was used in each case together with the respective polygons to estimate the GRV. This was varied by approximately +/- 30% to provide a range for input to the Monte Carlo and to account for uncertainties in the interpretation and depth conversion E1000 Prospects Three prospects have been mapped at the E1000 reservoir level. Their locations are shown in Figure 2-16 in Section 2 above. Polygons were used to constrain the areas of the prospects and these are shown in Figure Prospect 3 assumes that the Otakikpo-003 well penetrates the E1000 reservoir to the north of the bounding fault. If this well actually enters the reservoir to the south, the volume of hydrocarbons in place will be significantly reduced because this well encountered an OWC well above the closing contour. For the purposes of this evaluation, it is assumed that this structure has not been sampled by the well and is therefore considered a prospect. The GRVs for the three prospects were calculated based on the areas defined by the polygons and combined with the properties in Table 4-1. The resulting hydrocarbon in place estimates are shown in Table 4-12 below. STOIIP (MMbls) Reservoir P90 P50 P10 E1000 Prospect E E1000 Prospect E E1000 Prospect E TOTAL* Table 4-12: E1000 STOIIP * Note: Totals are arithmetic summations The closing contour was used in each case together with the respective polygons to estimate the GRV. This was varied by approximately +/- 30% to provide a range for input to the Monte Carlo and to account for uncertainties in the interpretation and depth conversion. 34

53 Summary of volumes The following tables summarise the Prospective STOIIPs by prospect to show the volumes associated with each stacked prospect. Prospect Prospect 1 Reservoir STOIIP (MMbls) P90 P50 P10 C C C TOTAL* Table 4-13: Prospect 1 STOIIP Prospect Prospect 2 Reservoir STOIIP (MMbls) P90 P50 P10 C C C E TOTAL* Table 4-14: Prospect 2 STOIIP * Note: Totals are arithmetic summations Prospect Reservoir STOIIP (MMbls) P90 P50 P10 Prospect 3 E TOTAL Table 4-15: Prospect 3 STOIIP Prospect Reservoir STOIIP (MMbls) P90 P50 P10 Prospect 4 E TOTAL Table 4-16: Prospect 4 STOIIP * Note: Totals are arithmetic summations 35

54 5. OML 11 Reservoir Engineering Review 5.1. Introduction The Otakikpo field, OML11, is located in the coastal swamp area of the eastern Niger delta, approximately 20 km west of the Opobo field. A number of 2D seismic lines were shot by Shell between 1971 and 1982 which led to the drilling of three wells and the discovery of the field. The existing wells: 001; 002 and 003, are situated across three fault blocks, with multiple hydrocarbon bearing horizons in 002 and 003. However 001, in the most northerly fault block, encountered predominately shale within the target sequence with no hydrocarbons. Neither 002 or 003 were tested; however, log data show the sands to be of good quality. RFT samples were taken in the 003 well from the C5000 and E1000 reservoirs, confirming the presence of good quality oil PVT and Fluid Properties Three RFT samples were taken in the Otakikpo 003 well: one from the shallower C5000 and two from the E1000; all confirm the presence of high API oil. Other data confirm that the reservoirs are normally pressured with a hydrostatic gradient range of between to psi/ft. PVT parameters for input into the simulator were generated using correlations. Data from the 1257RFSAD sample was used, as Shell states that it was the cleaner of the two E1000 samples. The measured sample parameters are given in Table 5-1 below. Horizon Sample # Sample Depth (ft MD) Sample Depth (ft TVDss) Oil API Res. Press. (psia) Res. Temp. ( F) Pb (psia) Bo Rs µ o (cp@sc) C RFSBC 8,755 8, E RFSAD 11,546 10, RFSBC 11,546 10, NOTE: Sample 1257RFSAD was the cleanest and therefore used in subsequent analysis Table 5-1: Otakikpo RFT sample parameters 5.3. Volumetrics and Properties Using the top surface maps of the four horizons as generated from the 2D seismic, and P50 petrophysical parameters, a series of reservoir models were constructed. Small adjustments to the NTGs were applied to match the models in-place volumes with the P50 volumes generated from Kingdom. The basic input parameters for the models are shown in Table 5-2 below. 36

55 Horizon P50 STOIIP (MMstb) P50 GIIP (Bscf) NTG (frac) Por. (frac) Perm (md) Sw (frac) Bo (rb/stb) Gas Exp. (st ft 3 /ft 3 ) C5000 (002 area) C5000 (003 area) C C E Note: kv/kh = 0.1 for all horizons Table 5-2: Model input parameters (P50 values) Reference depths, pressures and temperatures are also given in Table 5-3 along with the corresponding P50 contact depths. As neither of the wells had core or pressure transient data that could be used to derive permeability, values from an earlier Shell study were used. Permeabilities are very good and range from 967 to 1824mD, which is consistent with analogue fields in the Niger Delta. Horizon Reference Depth (ft TVDss) Res. Press (psia) Res. Temp. ( F) Oil API Pb (psia) Model OWC (ft TVDss) Model GWC (ft TVDss) C5000 (002 area) ,320 (ODT) 8,296 Oil Column at 002 (003) (ft TVD) 53 (Gas) 44 (Oil) C5000 (003 area) 8, , C6000 8, , C7000 8, , E , , Table 5-3: Initial pressures and contact depths Relative permeabilities were estimated based on Corey curves and exponents. A residual oil saturation of 20%, and a critical gas saturation of 3% were assumed. The values used are given in Table 5-4 and Table 5-5, and are based on regional experience. Horizon Initial Sw C5000 (002 area) - C5000 (003 area) 0.40 C C E Table 5-4: Summary of initial Sw assumed for key reservoirs 37

56 Water-Oil Krwo Exp Sorw Korw Exp Pc Oil-Gas Sorg Krog Exp Sgr Krgo Exp Pc Table 5-5: Rel-perm values and end points 5.4. Model Construction Kappa s Rubis software was used to model the reservoirs using Voronoi grids which are generated once an external boundary, internal faulting and layering are defined. Due to the very similar top surface maps for the C horizons, a single model; which included the C5000, C6000 and C7000 reservoirs was constructed. The E1000 model was built separately as this required a substantially different top surface map and PVT properties. Figure 5-1 shows the top grid for the C5000 surface; the four wells marked were used as part of the development plan for this horizon. Figure 5-1: Simulation grid showing top surface for the C5000 Horizon (Note: A larger version of the depth map at top left can be found in Figure 4-1) 38

57 The seismic interpretation indicated that the sands found in the 002 and 003 wells are areally extensive and this was assumed when constructing the model. However, none of these sands appear in the Otakikpo 001 well which is some 1,000m to the north in the next fault block and contains no hydrocarbons and is predominately shale. The reason for this is unclear. Table 5-6 below shows the layering scheme used in the model. Due to the limited data the sands are assumed to be of constant thickness within each fault block and extend to the defined boundaries at the edge of the maps. The top and bottom depth of each sand within the model agree with the well picks. Horizon Layer No. No. of Sublayers Description Well 002 Well 003 Top Surface 8,243 8,302 C Thickness Thickness Thickness Bottom 8,318 8,420 Inactive 4 1 Thickness Top 8,382 8,377 C Thickness Thickness Thickness Bottom 8,492 8,471 Top Surface 8,684 8,641 C Thickness Thickness Thickness Thickness Bottom 8,947 8,845 Top 10,557 10,626 E Thickness (Separate model) 2 2 Thickness Thickness Bottom 10,787 10,884 NOTE: The top of C7000 is defined by its top surface map (all depths in ft TVDss) Table 5-6: Otakikpo - Model layer scheme 39

58 The C horizon model consists of 11 layers, which is further subdivided in the top most layer to account for the initial distribution of hydrocarbons and secondary gas cap formation. It is know from observing nearby analogues, that fields in the Niger delta generally have very good aquifer support which leads to high recoveries. As a consequence once the models were constructed, they were run with a range of aquifer sizes for the P90, P50 and P10 cases. In the P90 case, no additional numerical aquifer was added and the aquifer consisted only of water below the OWC in the existing grid cells and resulted in sizes that were times that of the STOIIP. In the P50 case, a numerical aquifer was added to bring the total aquifer size to approximately 30 times that of the in-place oil, while an aquifer size of 40 times was used in the P10 case. Well numbers are assumed to be the same in each case Wells All wells were initially modelled as vertical. Individual perforations were defined for each reservoir layer and these were adjusted on the later models to ensure sufficient stand-off from secondary gas caps. These initial wells were further optimised by use of dual completions in order to reduce the well count. The C7000 reservoir lies directly below the C6000, and therefore could be developed using dual completions in two of the C6000 wells. The E1000 reservoir is offset by some 1,500ft from the C6000, but is some 2,000ft deeper, so by using S-shaped wells it was possible to specify dual completions with two of the C6000 wells. The well scheme is summarised in Figure 5-3 overleaf. Further optimisation of the well count may be possible by using one or more dual completion wells to produce three zones, by deferring perforation of the third zone until one of the other zones is depleted. However this level of optimisation would not be appropriate at this stage of resource assessment. Tubing pressure losses were calculated from the top of the reservoir to surface, assuming a 3.5 OD (2.75 ID) tubing. All wells were controlled on a minimum FTHP of 145 psia which was based on a 10 bar separator pressure. Maximum liquid rates of 1,500 blpd were imposed for most vertical wells. Individual perforations were shut-in once water cuts exceeded 95% Gas liberation For any oil reservoir ultimate recovery is a function of cumulative GOR (Rp). As the size of aquifer increased from the x10-18 (P90) to x30, the level of pressure support also increased and this was observed as a reduction in the amount of liberated gas. Figure 5-2 shows cross sections of the C6000 and C7000 reservoirs: the first image shows initial saturation conditions, while subsequent images show saturations at the end of the simulations for the P90 and P10 cases respectively. In the latter, the larger aquifer results in less liberated gas, smaller secondary gas caps and higher recoveries. As a consequence, the vertical wells are less prone to gas coning and are able to recover greater volumes before watering out. 40

59 Initial conditions in C6000 & C7000 reservoirs. Final conditions for small aquifer (P90) case. Final conditions for larger aquifer (P10) case Figure 5-2: Cross-sections of C6000 and C7000 reservoirs 41

60 5.5. Forecast Scenarios In order to determine the optimum number of wells for an Otakikpo development, the models for the C5000 (003 Area), C6000 and E1000 were run with 2, 4, 8 and 16 wells and the recoveries compared as well numbers increased. A summary of the results for E1000 are shown in Table 5-7 and Figure 5-4. As can be observed, most of the volumes are recovered by two wells with 0.5MMstb of incremental recovery at each well number doubling. Considering the cost of individual wells (~$20mln), balanced with the potential heterogeneity of the reservoirs (which is not reflected in the current models) it is likely that around four vertical wells per horizon would be prudent, although this number was refined in the final dual completion well scheme. The P90, P50 and P10 models were run for each horizon assuming a vertical well development using the well scheme shown in Figure 5-3, and the schedule given in Table 5-8. In each case it was assumed that the 002 well would be recompleted in the E1000 and C6000, while the 003 well would be recompleted in the E1000 and C5000 horizons. The dates shown in the notional drilling schedule are the assumed dates of first production, hence drilling would start in Q4/2016 for the first new well W1 to come on stream from 01/01/2017. Each new vertical producer is assumed to take 62 days to drill and complete, while each new S-shaped producer is assumed to require 75 days for drilling and completion. REVISED DUAL COMPLETION SCHEME VERTICAL and 'S' WELLS Completion Locations E1000 C5000 C6000 C7000 (003 Area) WELL 002 X X 003 X X W#1 X X W#2 X X C5 #1 X C5 #2 X C5 #3 X W#3 X X W#4 X X 'S' shaped wells New dual completed wells W#1, W#2, W#3, W#4 Figure 5-3: Wells and dual completion scheme The new wells are assumed to be distributed as follows: C5000 Southern Block: 3 new wells C6000 Central Block: 4 new wells (2 dual completions combined with the C6000 reservoir, and 2 with the E1000 reservoir) 42

61 The E1000 Southern Block is interpreted to be in communication with the Central block (assumed common contact), thus in addition to the recompletions in the 002 and 003 wells, two new wells will be required in the central part of the accumulation which will be dual completions (E1000 and C6000). The resulting recovery factors and STOIIPs were used in a Monte Carlo analysis to derive a probabilistic range of ultimate recoveries for each horizon and field. (see Table 5-9). 43

62 OML 11 E1000 Model run from 01/01/2016 to 31/12/2039 Full Field Models k = 967mD STOIIP (MMstb) STOIIP/ Well No. of wells Prod. Mode (NF/AL) +1yr (2017) Oil Recovery Factor +2yrs (2018) +4yrs (2020) +6yrs (2022) +30yrs (2036) Cum Oil Recovery per Well (MMstb) +1yr +2yrs +4yrs +6yrs +30yrs Aquif. SIze Cum Rec (MMstb) (6yrs) (30yrs) EUR Oil RF (30yrs) wells NF THP x32* wells NF THP x32* wells NF THP x32* wells NF THP x32* NOTE: *Models originally run with an aquifer x 32 which resulted in recoveries of 34 to 39%. The aquifer size was reduced to between for later runs. Table 5-7: E Summary of models runs with sensitivities of recovery vs. well numbers Oil Rec Fac OML11 E1000 Oil Rec Fac vs. STOIIP/Well Oil RF (@ +30 yrs) (@ 2036) Oil RF (@ +6 yrs) (@ 2022) Oil RF (@ +4 yrs) (@ 2020) Oil RF (@ +2 yrs) (@ 2018) Oil RF (@ +1 yrs) (@ 2017) STOIIP/Well (MM stb) Cumulative Oil at 2043 (MM stb) E1000 Total Recovered Oil vs Well Number No of Wells Figure 5-4: E1000 Sensitivity of recovery vs. well numbers 44

63 Vertical Wells Horizon Well Names/Number & First Production Dates W1 W2 W3 W4 C5#1 C5#2 C5#3 E /01/15 01/02/15 01/01/17 17/03/17 C Area 01/02/15 31/05/17 01/08/17 02/10/17 C /01/15 01/01/17 17/03/17 03/12/17 16/2/18 C /12/17 16/2/18 Table 5-8: Otakikpo Well schedule Monte Carlo Analysis of Otakikpo Horizon STOIIP / GIIP Recovery Factor P50 EUR (MMstb) Probabilistic Rec. Factor STOIIP x Horizon P90 P50 P10 P90 P50 P10 P50 RF P90 P50 P10 P90 P50 P C5000 (002) EUR C5000 (002) C5000 (003) C5000 (003) C C C C E E FIELD FIELD NOTE: C5000 (002 Area) not explicitly simulated due to small STOIIP and thin oil leg. Recovery factors from C7000 applied. Probabilistic recovery factors calculated by EUR/STOIIP for the P90, P50 and P10 cases. Table 5-9: Otakikpo - Monte Carlo results to determine ultimate recovery 45

64 Production Profiles A comparison of the recoveries derived from the modelling is shown in Table 5-10 below: Well E1000 Recovery per Well and Horizon (MMstb) C5000 (003 Area) C6000 C7000 Raw Totals Adjusted Totals* W W C5 # C5 # C5 # W W EUR STOIIP RF Table 5-10: Otakikpo - Recoveries for the P50 case Note: * Represents the Raw Totals scaled in order to match the total P50 Probabilistic EUR listed in Table 5-9. The resulting profiles for the P90, P50 and P10 are shown in Figure 5-5 and Table 5-11 (overleaf). In general the development of GOR is reduced as the aquifer size increases. Peak oil rates of 17,500 to 18,400bbls/d are achieved for all cases; however in the P90 case, where the aquifer is smallest, gas rates as high as 85MMscfd result. In the P50 and P10 cases, gas rates are 47 and 32MMscfd respectively. Individual perforations are shut-in at 95% water cut which results in a maximum field water cut range from 31% to 37%. 46

65 Figure 5-5: Otakikpo Notional production profiles for the P90-P50-P10 cases 47

66 CASE P90 P50 P10 Year Oil Rate Mbbls/d Cum Oil MMbbls Oil Rate Mbbls/d Cum Oil MMbbls Oil Rate Mbbls/d Cum Oil MMbbls Table 5-11: Otakikpo Oil prod. profiles P90-P50-P10 cases (100%) 48

67 5.6. Results and Conclusions A development requiring the recompletion of the two existing wells and the drilling of seven new vertical wells could achieve peak oil rates of 17,500 to 18,400bopd. Depending on aquifer size, ultimate recoveries of 49.8 to 66.8MMstb can be achieved. GOR development remains low in the P50 and P10 cases where the aquifers are larger, resulting in lower cumulative GORs and higher recoveries. Maximum gas rates are 47 to 32MMscfd respectively compared with 85MMscfd in the P90 case. Recoveries of 6.36 to 8.42MMstb per well are achieved through the dual recompletions of the existing 002 & 003 wells. Average recovery factors range from 31% in the P90 case to 42% in the P10 case where the aquifer is largest. This higher value is reasonable for Niger delta fields Further Studies The current model is based on a sparse data set of 2D seismic lines and limited well data however once additional wells are drilled and further seismic is available, the potential of using horizontal wells could be studied in more detail. Based on the performance of similar fields in the area it is likely that aquifer support will be good and therefore GORs will remain reasonably low, leading to good recoveries. No modelling work was done on the C5000 (Area 002) reservoir in this study, this was due to the small STOIIP, thin oil leg and gas cap. This horizon could either be produced as vertical wells are recompleted from deeper layers or it could be exploited with its own dedicated horizontal well. A more detailed understanding of this reservoir would be required before any further planning could be undertaken. 49

68 6. Otakikpo Facilities Review and Cost Estimates 6.1. Introduction The Otakikpo field in OML 11 is located near the coast in the Niger Delta about 32km east of the Bonny Island oil terminal. The access roads and well locations from the early 1980 s drilling campaign can be readily identified on satellite images (see Figure 6-1 below), which also shows the location of the processing facilities planned by Lekoil. Figure 6-1: Location map for planned Otakikpo production facilities (Source: Lekoil and Google Earth) 50

69 6.2. Overview of Otakikpo conceptual Central Production Facilities The following points summarise the key facilities information and guidance provided by Lekoil mid-july 2014 (see Figure 6-2 for proposed lay-out and Figure 6-3 for the conceptual process flow diagram): The main O&G production facilities proposed are quite simple and robust: o Two stages of separation are needed to give fully stabilized crude o Crude and produced water storage for 14 days gross production o Crude to be exported via a purpose built jetty to a nearby moored, refurbished FSO (Floating Storage and Offloading vessel) o Local crude barges offload the FSO, on a routine basis, to a nearby oil terminal (for onward shipping and processing) o Two years after First Oil, a 30 km crude oil export pipeline tying into a regional oil evacuation system will be commissioned The CPF plot plan needs to accommodate large atmospheric storage tanks (around 250,000 barrels storage capacity). Figure 6-2: Conceptual lay-out of proposed Otakikpo CPF (Source: Lekoil) 51

70 Figure 6-3: Conceptual process flow diagram for Otakikpo CPF (Source: Lekoil) The following points summarise the main high-level Facilities Engineering inputs to the current concept-level cost estimation work: Following extensive geophysical and geotechnical site surveys of the field, the necessary land acquisition will be made for the flow lines, oil export pipeline, electric power cable route etc. rights-of-way and the Central Production Facility (CPF) site. It is intended that the well site locations, access routes and the CPF site would be sand filled. The CPF will have initial capacity for about 18,000bpd (expandable to 35,000bpd by adding additional train at a future date). The Facility will comprise an oil inlet manifold for the hook up of the four off flow lines from the initial two off oil wells with spare slots for hook-up of future wells for the full field development. The inlet manifold will have separate headers for concurrent production and well testing purposes. The facility will be equipped with necessary process controls, protection and safeguards. The light, sweet well stream fluids are separated into water in oil and gas. The oil/water stream will flow to the crude oil storage tanks where further separation into oil and water by gravity settling will take place. The storage tanks will have combined capacity to hold 14 days production of gross liquid. The produced water will be treated to EGASPIN specification then pumped to a produced water storage tank for temporary storage and subsequent evacuation by loading barge and transportation offshore for disposal in accordance to Nigerian regulatory guidelines. Produced oil will be evacuated from site by barging and transported to a nearby Terminal. A shallow offshore jetty will be constructed for the mooring of, and crude offloading to, a Floating Storage and Offloading (FSO) vessel. Local crude barges will 52

71 offload the moored FSO on a regular basis. At the point of custody transfer there will be fiscal metering of barged crude oil. The associated gas will be used for the (CPF) plant utility, plant power generation and external electrical power supply to the immediate community as part of social performance and community development initiatives. Surplus associated gas will be supplied to third party at the battery limit. It should be noted that: The Otakikpo well fluid is sweet with no H 2 S and minimal levels of CO 2, Minimal gas processing is required (basic dehydrating and dew-pointing) and Gas compression and export pipeline facilities, as advised by Lekoil, are not included for in the current FDP concept. It was also advised that any gas compression and pipeline export requirements would be accommodated by a third party with gas being supplied from the Otakikpo CPF on an over the fence basis Otakikpo facilities cost estimates The key assumptions were as follows: Facilities cost estimates are to be developed for P50, P90 and P10 resource levels (as per Table 6-1). Two existing exploration/appraisal wells are to be re-entered and completed as dualcompletion wells (Otakikpo-002 and -003), with a rig mobilized in Q4/2014 such that the first recompleted well can be brought on stream very early in D seismic survey to be acquired in early 2016 (estimated cost $15mln). For the full field development, vertical wells are to be considered as the base-case development scenario: o A total of 7 new-drill vertical wells to be considered; two of which will be dual completions in the C6000 and C7000, and two of which will be S-shaped dual completions in the C6000 and E1000 (Table 6-1). First new well drilled late o Note: wells do not require artificial lift. Storage for 250,000 barrels of gross production to be provided by on-site atmospheric tanks, which corresponds to 14 days production at plateau rates once the full-field development is completed. Crude to be initially exported via a nearby moored leased FSO (Floating Storage and Offloading) tanker dedicated to the field, with local crude barges offloading the FSO to nearby terminal. Two years after First Oil, a 30 km crude oil export pipeline tying into a regional oil evacuation system will be commissioned as the main oil export facility for the field. Gas is to be conditioned for use as fuel gas (power generation) and is assumed to be dehydrated and dew-pointed. Gas compression is to be considered as a separate, future project (by third party). Infield crude oil pipeline and jetty transfer crude to FSO. Fiscal metering occurs initially at barge entry point and into terminal, and later at tie-in of oil export line to regional crude evacuation system. 53

72 Vertical Wells - Otakikpo Res. Eng. Assumptions for Facils. Eng. Description Units P90 P50 P10 Comments STOIIP MMstb GIIP BCF Well No s 7 (+2) 7 (+2) 7 (+2) 7 new wells; two with dual completions (C6000 and C7000) and 2 S-shaped dual completions in the C6000 and E1000. Max. Field Rate blpd 18,400 19,500 19,500 bopd 17,100 17, MMscf/d Ult. Recovery MMstb Technically recoverable volumes Max. Liq. Rate/completion bopd 1,500 1,500 1,500 Dual completed wells produce at up to 3,000 bopd Max. Field Water Cut % 31% 33% 34% Individual perf s closed in at 95%, however lower WC per well due to tubing effects. NOTE: No artificial lift assumed. All wells controlled on FTHP, with minimum FHTP of 145psi. Table 6-1: Res. engineering inputs for P90-P50-P10 dev. scenarios Cost estimates were developed using Que$tor supplemented with inputs based on similar regional onshore fields development norms and costs following recent Facilities Engineering project work done on neighbouring blocks in that part of the Niger Delta region. Mindful of this, and of the current level of project definition and Facilities Engineering work done to date on Otakikpo, the concept-level Capex and Opex estimates reported here are assumed to have an accuracy of +/- 30%. As noted above, cost estimates were developed for the P90-P50-P10 reservoir development scenarios assuming vertical (and two deviated wells), see Table 6-2 to Table 6-4. The cost phasings for these cases are summarised in Table 6-5. Cost efficiencies have achieved by use of dual completions in some wells, and this required S-shaped wells to be specified for the E6000/E1000 wells. Due to the smaller aquifer assumed for the P90 case, a significantly higher gas rate is forecast than for the P50 and P10 scenarios, resulting in marginally higher overall capex for the P90 case compared to the P50 and P10 cases. 54

73 P90 Oil Case VERTICAL Wells Description Oil Storage and Offloading Tanker Well Drilling (Land Rig) All costs in US$mln (100%) Well Site Facils. Central Prod. Facility Oil & Water Storage and Offloading Infield Oil Transfer Pipeline Roads, Camps, Buildings TOTALS (US$mln) Equipment Materials Fabrication Prefabrication Install. & Constr H. U. & Comm Design Proj. Mgmt Insur. & Cert Contingency TOTALS Table 6-2: Overview of AGR TRACS cost estimates for P90 Case P50 Oil Case VERTICAL Wells Description Oil Storage and Offloading Tanker Well Drilling (Land Rig) All costs in US$mln (100%) Well Site Facils. Central Prod. Facility Oil & Water Storage and Offloading Infield Oil Transfer Pipeline Roads, Camps, Buildings TOTALS (US$mln) Equipment Materials Fabrication Prefabrication Install. & Constr H. U. & Comm Design Proj. Mgmt Insur. & Cert Contingency TOTALS Table 6-3: Overview of AGR TRACS cost estimates for P50 Case with vertical wells 55

74 P10 Oil Case VERTICAL Wells Description Oil Storage and Offloading Tanker Well Drilling (Land Rig) All costs in US$mln (100%) Well Site Facils. Central Prod. Facility Oil & Water Storage and Offloading Infield Oil Transfer Pipeline Roads, Camps, Buildings TOTALS (US$mln) Equipment Materials Fabrication Prefabrication Install. & Constr H. U. & Comm Design Proj. Mgmt Insur. & Cert Contingency TOTALS Table 6-4: Overview of AGR TRACS cost estimates for P10 Case 56

75 Capex Cost Phasing US$mln (100%) P90 OIL Drilling: Facilities: End of econ. life TOTAL Tangible Intangible Facilities Pipelines Other Facils TOTAL CAPEX Abandonment P50 OIL Drilling: Facilities: End of econ. life TOTAL Tangible Intangible Facilities Pipelines Other Facils TOTAL CAPEX Abandonment P10 OIL Drilling: Facilities: End of econ. life TOTAL Tangible Intangible Facilities Pipelines Other Facils TOTAL CAPEX Abandonment Table 6-5: Overview of capex phasing for P90-P50-P10 cases 57

76 Note that the estimated abandonment costs shown in Table 6-5 are significantly greater than what is prescribed in the January 2014 Otakikpo Marginal Field farm-out agreement between NNPC/Shell/Total/Agip and Green Energy. Schedule C (p. 46) of the farm-out agreement defines a decommissioning and abandonment security to be accrued according to the formula: Where: Y = [0.1 D/t]*(1+r) (t-n) Y = Amount to be paid annually into an escrow account as abandonment security D = Development cost of field 0.1D = 10% of development cost of field t = expected field life r = LIBOR rate n = particular year of production The cumulative amount accrued over the economic field life under this formula is about 40%-45% of the total abandonment costs as estimated by AGR TRACS. The difference may therefore imply a further unfunded late-life abandonment liability. The notional opex estimates for the four cases are summarised in Table 6-6 below: Opex Category P90 P50 P10 Fixed Opex ($mln/yr) Variable Opex ($/bbl) Table 6-6: Opex assumptions for notional Otakikpo development cases 58

77 7. Economic Evaluations 7.1. Summary of Otakikpo OML 11 Marginal Field Terms Otakikpo is held under Marginal Field Terms by Green Energy, which are a Tax & Royalty scheme with reduced tax rates. The key points are summarised below: Capital investments eligible for Capital Allowances over 5 years (20%, 20%, 20%, 20% and 19%) Investments eligible for Investment Tax Allowance (ITA) of 20% Petroleum Profit Tax (PPT) rate of 55% Education Tax rate of 2% of assessable profits before fiscal depreciation (deductible for PPT purposes) Royalty on crude production (which is deductible for PPT purposes) is payable in tranches based on production rates; as follows: Production below 5,000 bopd: 2.5% 5,001 10,000 bopd: 7.5% 10,001 15,000 bopd: 12.5% 15,001-25,000 bopd: 18.5% An over-riding royalty charge of 6% (< 10,000 bopd) and 7.5% (> 10,000 bopd) is payable to the head farmors (NNPC/Shell/Total/Agip). Losses and unutilized Capital Allowances can be carried forward indefinitely No dividend withholding tax on profits which have been subjected to PPT Contribution to Niger Delta Development Commission (NDDC) fund of 3% of the company s annual budget (i.e. taken to apply to both capex and opex) Cashflow available for cost recovery: 80% AGR TRACS has audited the Lekoil economic model, and the above fiscal terms have been fully captured in the model Economic Assumptions The P90-P50-P10 cases were assessed using discounted cashflow models (DCF) from based on the above fiscal terms. The PV reference date is , and the NPVs are quoted on a Money Of the Day (MOD) basis. A range of discount rates (0%, 10%, 15%, and 20%) were used, with mid-year discounting. Under the terms of the farm-in agreement, Lekoil Nigeria carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy s share of the initial work program is reflected in Lekoil Limited s 36% share of project NPV. The oil price scenarios used were $80-$100-$120/bbl, escalated at 2.5%/year from 2015 onwards. Costs were similarly escalated. Economic cut-offs were applied to all NPVs and estimates of net unrisked contingent resources. The end of economic life was defined as being reached when Opex (incl. the 3% NDDC charge) plus Royalty exceeded the gross oil production revenues. The production profiles and the associated capex and opex cost profiles for the four cases are listed in sections 5.5 and

78 7.3. Economic Evaluations The results of the AGR TRACS economic evaluations under the % discount rates of Lekoil s net 36% share in the Otakikpo Marginal Field (OML 11) are summarised below in Table 7-1 to Table 7-4 for the P90-P50-P10 cases. The results indicate that the P90-P50-P10 cases are economically robust at NPV(10%) under the three oil price scenarios assumed, with the farm-in terms included. Note: These NPV s are for Lekoil Limited s 36% interest in the project held via their 90% interest in Lekoil Nigeria. Otakikpo Case Cont. $80/bbl (MMbbls) NPV(0%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table 7-1: Otakikpo Econ. results NPV(0%) for P90-P50-P10 cases net to Lekoil Limited Otakikpo Case Cont. $80/bbl (MMbbls) NPV(10%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table 7-2: Otakikpo Econ. results NPV(10%) for P90-P50-P10 cases net to Lekoil Limited Otakikpo Case Cont. $80/bbl (MMbbls) NPV(15%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table 7-3: Otakikpo Econ. results NPV(15%) for P90-P50-P10 cases net to Lekoil Limited Otakikpo Case Cont. $80/bbl (MMbbls) NPV(20%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table 7-4: Otakikpo Econ. results NPV(20%) for P90-P50-P10 cases net to Lekoil Limited 60

79 8. Contingent Resource Estimates On the basis of the economic evaluations discussed in Section 7.0 the net contingent resources attributable to Lekoil Limited have been summarised in the sections below, based on Lekoil Limited s 90% interest in Lekoil Nigeria which in turn now holds a 40% interest in the Otakikpo Marginal Field Lekoil Net Contingent Resources under $80-$100-$120/bbl Table 8-1 below summarises Lekoil s net contingent resources for the evaluated Otakikpo P90-P50-P10 cases with vertical wells under the three oil price scenarios assumed for the economic evaluations. Lekoil Limited Net Unrisked Contingent Resources MMbbls Otakikpo $80 $100 $120 P Last Year of Production Lekoil Limited Net Unrisked Contingent Resources MMbbls Otakikpo US$80/bbl US$100/bbl US$120/bbl P Last Year of Production Lekoil Limited Unrisked Contingent Resources MMbbls Otakikpo US$80/bbl US$100/bbl US$120/bbl P Last Year of Production Table 8-1: Otakikpo Lekoil net P90-P50-P10 Unrisked Contingent Resources 61

80 8.2. AIM Summary Tables The tables in this section have been compiled in a manner consistent with that prescribed by the London Stock Exchange June The volumes reported assume that Lekoil Nigeria will complete the acquisition of the planned 40% equity interest in the Otakikpo Marginal Field (OML 11) from Green Energy International Ltd, and that Lekoil Limited becomes represented in OML 11 from late 2014 onwards through its 90% interest in Lekoil Nigera. The quoted contingent resources therefore represent the economically recoverable volumes from the planned date of first production ( ) till end of economic life for the stated fields under an oil price of $80/bbl (RT). The Chance Of Commercial Success (COCS) for the entire development of Otakikpo is currently assessed at 70%, as there is at present no agreed or approved development plan. However, as work progresses over the next few months it appears likely that some of the early drilling activity will be approved, thus the resource classifications and risk ratings will be revised in due course. 62

81 Oil & Gas Reserves There are currently no attributable reserves in the Otakikpo field, as the development plan has not yet been sanctioned. Work is in progress to initiate recompletion of the 002 and 003 wells late in Q4/2014, thus by that time the net attributable volumes anticipated from these two wells could be reclassified as reserves. The remainder of the future production from the later stage of the planned development will remain as Contingent Resources until the full field development plan has been approved by all partners. Oil & Liquids: MMbbls DISCOVERY 1P Proved Gross (from ) 2P Proved & Probable 3P Proved, Probable & Possible Net Attributable to Lekoil Limited (from ) 1P Proved 2P Proved & Probable 3P Proved, Probable & Possible Otakikpo Operator Green Energy Table 8-2: AIM table of Otakikpo OML 11 Reserves; gross and net attributable to Lekoil Note: Operator is the name of the company that operates the asset. Gross are 100% of the reserves attributable to the licence whilst Net Attributable are those attributable to the AIM company. Reserves calculated under US$80/bbl. MMbbls million barrels 63

82 Oil & Gas Contingent Resources Oil MMbbls Gross (from ) Net Attributable to Lekoil Limited (from ) Risk Factor Operator 1C Low Estimate 2C Best Estimate 3C High Estimate 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) Contingent Otakikpo % Green Energy Table 8-3: AIM table of Otakikpo OML 11 Contingent Resources; gross and net attributable to Lekoil Note: Risk Factor for Contingent Resources means the chance, or probability, that the hydrocarbons will be commercially extracted. Operator is the name of the company that operates the asset. Gross are 100% of the resources attributable to the licence whilst Net Attributable are those attributable to the AIM company. Contingent Resources calculated under US$80/bbl. MMbbls million barrels 64

83 Risked Contingent Resources Net to Lekoil (from ): Oil MMbbls Unrisked Contingent Resources Net Attributable to Lekoil Limited Risk Factor Risked Contingent Resources Net Attributable to Lekoil Limited 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) 1C Low Estimate 2C Best Estimate 3C High Estimate Contingent Otakikpo % Table 8-4: AIM table of Otakikpo OML 11 Contingent Resources net attributable to Lekoil; unrisked and risked Note: Risk Factor for Contingent Resources means the chance, or probability, that the hydrocarbons will be commercially extracted. Contingent Resources calculated under US$80/bbl. 65

84 Oil Prospective Resources STOIIP ranges have been estimated for four undrilled prospects as part of this review (see section 4.2.5), but due to lack of engineering and cost data for notional developments no estimates of recoverable volumes and no economic assessments have been carried out for these prospects. Oil & Liquids: MMbbls PROSPECTIVE RESOURCES (Technical Resources) Prospect 1 Prospect 2 Prospect 3 Prospect 4 Gross (on-block) Net Attributable to Lekoil Limited (40% of Gross on-block resources) Low Mid High Low Mid High Operator Table 8-5: AIM table of Otakikpo OML 11 Unrisked Prospective Resources; gross and net attributable to Lekoil Note: No risk factors estimated due to lack of technical data MMbbls million barrels 66

85 9. Conclusions AGR TRACS has carried out a full review of the Otakikpo Marginal Field based on data provided by Lekoil and independent development cost estimates for a notional development scheme according to an outline provided by Lekoil in mid-july There is no approved development plan at present, hence the volumes assumed to be recovered through the initial recompletions and the subsequent development scheme have been classified as Contingent Resources with a Chance Of Commercial Success (COCS) of 70%. The Contingent Resource estimates have been derived using an economic model provided by Lekoil and reviewed by AGR TRACS. This is considered to correctly represent the Marginal Field Terms applicable to Otakikpo. The net attributable volumes quoted in this report reflect the farm-in terms agreed with Green Energy in May 2014 in order to transfer a 40% equity interest in the Otakikpo Marginal Field in OML 11 to Lekoil Oil and Gas, with 90% of this interest attributable to Lekoil Limited. The completion of the transfer requires a formal approval from the Minister of Petroleum Resources. However, Lekoil Oil and Gas and Green Energy have executed a Financial and Technical Services Agreement (FTSA) whereby Lekoil Oil and Gas is entitled to a 40% economic interest in the Otakikpo Marginal Field. Under the terms of the farm-in agreement, Lekoil Oil and Gas will carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy s share of the initial work program is reflected in Lekoil s share of project NPV. Following the review, AGR TRACS can report that the net unrisked 1C-2C-3C (P90-P50-P10) Contingent Resources at $80/bbl attributable to Lekoil (effective from late 2014) are estimated to be MMbbls. The corresponding net risked 1C-2C-3C (P90-P50-P10) contingent resources at $80/bbl attributable to Lekoil are estimated at MMbbls oil, see Table 9-1 below. Four exploration prospects have been identified. P90-P50-P10 STOIIP ranges have been estimated for these structures, however, insufficient data was available to enable economic evaluations to be carried out, thus no Prospective Resources can be estimated. Oil MMbbls Unrisked Contingent Resources Net Attributable to Lekoil Limited Risk Factor Risked Contingent Resources Net Attributable to Lekoil Limited 1C Low Estimate 2C Best Estimate 3C High Estimate COCS (%) 1C Low Estimate 2C Best Estimate 3C High Estimate Contingent Otakikpo % Table 9-1: Otakikpo OML 11 Unrisked and Risked Contingent Resources net attributable to Lekoil Economic evaluations have been carried out under $80-$100-$120/bbl oil price scenarios for the P90-P50-P10 cases with deviated wells from until end of economic life. The NPV(10%) MOD results of the economic evaluations indicate that the planned development of the Otakikpo Marginal Field is a robust project under all three oil price scenarios - see Table 9-2 for the NPV(10%) results (with the farm-in terms included). 67

86 Otakikpo Case Cont. $80/bbl (MMbbls) NPV(10%) $mln MOD PV % Lekoil Net $80 $100 $120 P P P Table 9-2: Otakikpo P90-P50-P10 cases - Economic results NPV(10%), unrisked net to Lekoil Limited 68

87 10. APPENDIX 1 - Petroleum Resources Classification Summary of 2007 SPE Petroleum Resources Classification The following paragraphs are quoted from the 2007 SPE PRMS Guidance Notes and summarise the key resources categories, while Fig. A-1 shows the recommended resources classification framework. Class/Sub-class Definition 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. On Production The development project is currently producing and selling petroleum to market. Approved for Development All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. 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. 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. Development Pending A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. Development Unclarified or on Hold Development Not Viable A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. 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. Prospective Resources Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Prospect A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. 69

88 Fig. A-1: 2007 SPE PRMS Petroleum Resources Classification Framework 70