Ekeh Field Competent Person’s Report for Midway … · Competent Person’s Report for Midway Resources International By AGR TRACS ... made to give effect to the original Marginal

Ekeh Field

Competent Person’s Report

for

Midway Resources International

By AGR TRACS

18th October, 2011

This report was prepared in accordance with standard geological and engineering methods generally accepted by the oil and gas industry. 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. TRACS International Consultancy Ltd. shall have no liability arising out of or related to the use of the report.

Status Final Final Version 3.3

Date 8th October 2011

Issued by

A. Spriggs

AGR Petroleum Services

Issued

Approved by Tom Gunningham Approved

Ekeh Field Competent Person’s Report

TRACS International Consultancy Limited 18th October 2011

i

Cover Letter

INDEPENDENT VOLUMETRIC REVIEW OF EKEH FIELD FOR MIDWAY RESOURCES INTERNATIONAL.

The Directors

Midway Resources International, C/- M&C Corporate Services Limited, P.O. Box 309, Ugland House, Grand Cayman KY1 – 1104 Cayman Islands

18th October 2011

Gentlemen,

Competent Person’s Report on Ekeh Field, Nigeria

In response to your request TRACS International Consultancy Limited (“TRACS”) has conducted an independent assessment of the potential in-place and recoverable volumes of the Ekeh Field, OML 88, Nigeria.

Following this evaluation TRACS International Consultancy can report that the Ekeh Field, discovered in 1986 contains potentially economic volumes of recoverable oil and gas. The Ekeh Field is currently at the appraisal stage, and requires further appraisal in order to optimise a field development plan. We currently assess the recoverable volumes in Ekeh as Contingent Resources, which subject to (i) completion of the pending farm-in agreement between MRI and Ekeh partners; (ii) renewal/extension of the Ekeh Farm-in Agreement, Middleton Production Platform lease and other relevant commercial agreements between Ekeh partners and OML88 owners; and (iii) confirmation of the physical integrity and usability of the Middleton Production Platform, wells and export system for production processing, gas disposal and oil export could be categorised as Reserves on approval of a Field Development Plan.

Our assessment indicates in place resources of 77.9 MMstb STOIIP and 36.8 Bcf Gas (P50 Estimate), with contingent resources of 12.3 to 34.0 MMstb, recoverable from three to seven (3-7) production wells.

Contingent Resources

Gross MMbbls/Bcf Net Attributable MMbbls/Bcf

Operator: Movido Min Est.

Low Est.

Base Est.

High Est.

Min Est

Low Est

Base Est.

High Est.

Ekeh Oil (MMbbls) 12.31 18.95 25.13 33.95 4.92 7.58 10.05 13.58

Ekeh Gas (Bscf) 17.26 19.57 28.95 34.75 6.91 7.83 11.58 13.90

TRACS Estimates of Gross and Net Attributable Contingent Gas Resources to MRI.

NOTE 1: Ekeh Field extends beyond the original farm-out area.

NOTE 2: It is currently planned to inject gas into Middleton Field for disposal, but the gas could be commercially re-produced at a later time if a market opportunity arises.

To reach the point where a Field Development Plan could be approved, an appraisal programme is proposed which will include appraisal drilling and long term testing. The capital costs for this appraisal programme are estimated to be $25-32 million for the drilling



ii

of 2 wells and the abandonment of Ekeh-2H, and a 6 month extended production test. If field development is then approved, an expected further $52-70 million development capital will be required to drill further wells, install a well head platform at Ekeh, and refurbish the Middleton Production platform.

The work was undertaken by a team of TRACS professional petroleum engineers and geoscientists based on data supplied by MRI. The data comprised details of licence interests, seismic and well data, technical interpretations, reports and presentations. TRACS have exercised due diligence and independent analysis where appropriate on all technical information supplied by MRI. TRACS have not independently checked title interests with Government or licence authorities.

Qualifications

TRACS International Consultancy Limited is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, TRACS International Consultancy 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 by Dr Andrew Spriggs, a geologist with 22 years industry experience, and approved by Tom Gunningham, a chartered petroleum engineer, with 23 years industry experience. TRACS International 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,

Tom Gunningham

Chief Reservoir Engineer,

TRACS International Ltd.



iii

Disclaimer

INDEPENDENT VOLUMETRIC REVIEW

Ekeh Field, 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. TRACS International Consultancy Ltd. shall have no liability arising out of, or related to, the use of the report.

18th October, 2011



iv

Executive Summary Midway Resources International (MRI) has requested that TRACS International Ltd produce a Competent Person’s Report on its estimates of Contingent Resources for the Ekeh Field in Nigeria.

At time of writing this report, MRI owns no commercial interests in the Ekeh Field, but intends to acquire an interest from some of the current partners. Subject to the completion of the planned acquisition MRI will gain a 40% interest in Ekeh Field which contains Contingent Resources. Subject to the planned appraisal programme and approval of a field development plan and completion of related commercial agreements, Ekeh resources can be upgraded to Reserves.

The proposed acquisition will include as conditions precedent the novation of the underlying Chevron/NNPC Farm-out Agreement and Lease of Middleton Production Platform that were made to give effect to the original Marginal Fields Program Award of the Ekeh Field to Movido Exploration & Petroleum Nigeria Limited in 2003.

The Ekeh Field, discovered in 1986 (Ekeh-1) is currently in the appraisal stage with a second well already drilled (Ekeh-2H). It is proposed to further appraise, place the field on production with two wells via an Early Production Scheme (EPS), and then fully develop the field with further wells using an unmanned well head platform tied back 7 km to existing processing facilities on the leased Chevron’s Middleton Production Platform. The Ekeh-1 well is assumed Plugged and Abandoned, but the Ekeh-2H well required abandonment during the first phase of planned field activity.

Table 1-1 Summary of Assets before MRI farm-in

Asset Operator MRI Interest

Status Licence Expiry Date

Licence Area

Comment

Ekeh Field

Movido Exploration & Production Ltd

0% Appraisal 14.3.2015 14.59 km2

Marginal Field Licence extension granted 14.3.2011.

Table 1-2 Summary of Assets after MRI farm-in

Asset Operator MRI Interest

Status Licence Expiry Date

Licence Area

Comment

Ekeh Field

Movido Exploration & Production Ltd

40% Appraisal & Development

14.3.2015 To be agreed

Subject conditions precedent

An independent assessment was made of the Contingent Resource volumes for Oil and Gas, and the probability that development would proceed. The Ekeh Field contains some 55 to 110 MMstbbl of oil in place plus 32 to 42 Bcf gas in place, distributed amongst a series of stacked reservoir. Field development options have been investigated to develop the oil resources. Some of the gas resources will be used for fuel and gas lift, but the majority will be re-injected. Each option calls for an early production scheme based on the initial two wells which will further appraise the field and enable MRI to optimise the Full Field Development Plan, with a proposed decision point after 6 months of production and the projected FFDP being commissioned at months 18-20 from the initial appraisal well.

Recoverable oil resources have been estimated using a probabilistic assessment shown by the curve in Figure 1-1. P90, P50 and P10 Resource volumes independently derived by Movido are also shown, and were found to be very similar to our own estimates. Deterministic estimates of reserves for a Minimum (>P90), Low (P75), Base (P50) and High (P10) cases were then developed.



v

Because the resources are distributed amongst several reservoirs over an uncertain area, an appraisal and early production plan was created with a decision tree to determine the optimal sequence of drilling to appraise and develop the field. From this decision tree (Figure 5-4), a series of 14 deterministic models were created, with development options identified. Of these, 4 representative development scenarios were selected with 3 (minimum), 4 (Low), 5 (Base) or 6 (High) wells for detailed reservoir modelling to estimate oil recovery.

No upside scenarios beyond the discovered resources in Ekeh Field have been addressed in this report.

The Minimum case scenario occurs if the oil is restricted to the minimum area around the existing two Ekeh wells in the southeast of the structure, with the minimal confirmed oil columns in all reservoirs, which would result in a 3 well development. This is our worst case, which would be worse than a P90 outcome, but yield economic results provided the Middleton Production Platform is available as a host facility for processing and export. If the oil extends slightly further than the minimum proven, either by deeper oil water contacts or over a larger area, it is likely that the field will require a 4 well development, which is regarded as a low case. Our base case assumes the oil extends as far as the structural closure mapped on seismic, resulting in a 5 well development scenario. This base case confirms Movido’s original estimates and demonstrates an economically feasible development opportunity. In the high case, with larger STOIIP, an extra 6th well would be needed to accelerate production.

Figure 1-1 Probabilistic distribution of Ekeh Oil Resources



vi

Contingent Resources

Gross MMbbls/Bscf Net Attributable MMbbls/Bscf

Operator: Movido Min Est.

Low Est.

Base Est.

High Est.

Min Est

Low Est

Base Est.

High Est.

Ekeh Oil (MMbbls) 12.31 18.95 25.13 33.95 4.92 7.58 10.05 13.58

Ekeh Gas (Bscf) 17.26 19.57 28.95 34.75 6.91 7.83 11.58 13.90

Table 1-1-3 TRACS Estimates of Gross and Net Attributable Contingent Resources to MRI.

The development scenarios adopted in this report require the use of the Middleton Production Platform as a host. If these facilities are either considered sub-optimal (technically or economically), alternative options for a stand alone development would need to be investigated. We estimate an 80% chance for the Ekeh Field to be developed with the main risk being the timely completion of the necessary commercial transactions for the planned acquisition by MRI. Secondary risks are project execution related – and include the refurbishment of Middleton Production Platform facilities and the necessary drilling and engineering resources. There is currently no plan to sell the produced gas due to lack of market and export facilities. Gas will be re-injected and stored. However, circumstances may change in future, so we estimate a 10% chance of developing Ekeh’s gas resources.

Midways proposed project schedule would see first oil to the Early Production System in Jan-13, first oil to Middleton facility Nov-2015 and the Ekeh field on Plateau with four to five (4-5) producers in the Base case by Apr-2015. TRACS/AGR views this project delivery schedule as fairly aggressive with some chance of slippage. To allow schedule delivery a number of activities must run concurrently and detailed work must begin on the Project Execution Plan, the App-1 and Dev-1 well proposals and the Ekeh-2H abandonment proposal 2011. The schedule is based upon the assumption that i) the Middleton Production Platform will require some upgrade, but that the majority of the existing equipment can be re-utilised ii) Movido has already progressed some engineering work on the development and iii) all commercial matters relating to the licence and Midways participation within the license are resolved in the near term. Early partner commitment and very detailed project management are key to schedule delivery.

Capital costs for the appraisal phase are estimated to be $25-32 million for the drilling of 2 wells and the abandonment of Ekeh-2H. Operating costs of $13.5 million are estimated for the 6 month extended production test, which would be offset by revenues derived from 5000-6000 bopd production.

If full field development is then approved, an expected further $52-70 million development capital will be required to drill further wells, install a well head platform at Ekeh and tie back to a refurbished Middleton Production platform. During the development period, it is envisaged that the EPS would continue to produce for about 1 year generating further early revenues to partially offset development costs.



vii

Contents

1. Introduction ......................................................................................................... 1

1.1. Licences and Agreements ................................................................................. 1

1.1.1. Midway Farm-in Agreement ........................................................................ 3

1.2. Exploration History .......................................................................................... 3

1.3. Appraisal Requirements ................................................................................... 5

1.4. Development Philosophy .................................................................................. 6

1.5. Project Schedule ............................................................................................. 7

1.6. Key Risks and Uncertainties ............................................................................. 8

2. Geology & Geophysics ........................................................................................... 9

2.1. Seismic Interpretation ..................................................................................... 9

2.1.1. Seismic /well data base .............................................................................. 9

2.2. Reservoir correlation ..................................................................................... 10

2.3. Horizon interpretation .................................................................................... 13

2.4. Depth conversion .......................................................................................... 16

3. Petrophysical Analysis ......................................................................................... 17

3.1. Data loading and edits ................................................................................... 17

3.2. Volume of clay ............................................................................................. 17

3.3. Porosity ....................................................................................................... 18

3.4. Water saturation ........................................................................................... 18

3.5. Permeability ................................................................................................. 19

4. Estimation of in-place hydrocarbon volumes ........................................................... 23

4.1. Uro-9 .......................................................................................................... 23

4.2. Iku-3 .......................................................................................................... 25

4.3. Iku-5 .......................................................................................................... 27

4.4. Iku-6 .......................................................................................................... 29

4.5. Ewinti-2.0 .................................................................................................... 31

4.6. Ewinti-2.1 .................................................................................................... 33

4.7. Ekeh Field Probabilistic STOIIP Summary ......................................................... 35

5. Ekeh Field Volumetrics & Uncertainty ..................................................................... 36

5.1. Deterministic STOIIP Segments ...................................................................... 36

5.1.1. Iku-3 .................................................................................................... 36

5.1.2. Iku-6 .................................................................................................... 37

5.1.3. Ewinti-2.1 .............................................................................................. 38

5.1.4. Ewinti-2.0 .............................................................................................. 38



viii

5.1.5. Deterministic STOIIP Volumes ................................................................... 39

5.2. Appraisal Programme .................................................................................... 39

5.3. Decision Tree ............................................................................................... 40

5.4. Minimum (Case 1) – 3 well development .......................................................... 43

5.5. Low (Case 5) – 4 well development ................................................................. 44

5.6. Base (Case 4) – 5 well development ................................................................ 45

5.7. High (Case 12) – 6 well development ............................................................... 46

6. Reservoir Engineering ......................................................................................... 47

6.1. Well Tests .................................................................................................... 47

6.1.1. Ekeh-1 .................................................................................................. 47

6.1.2. Ekeh-2H ................................................................................................ 48

6.2. Production History ........................................................................................ 48

6.3. Recovery Factors .......................................................................................... 48

6.3.1. Oil Recovery Factors ................................................................................ 48

6.3.2. Gas Recovery Factors .............................................................................. 49

6.4. Oil and Gas Properties ................................................................................... 50

6.5. Well Productivity ........................................................................................... 52

6.6. Material Balance Modelling ............................................................................. 54

6.7. Integrated Production System Model ............................................................... 56

6.7.1. Base Case (Case 4) – 5 well development ................................................... 57

6.7.2. Minimum Case (Case 1) – 3 well development ............................................. 62

6.7.3. Low Case (Case 5) – 4 well development .................................................... 64

6.7.4. High (Case 12) – 6 well development ......................................................... 67

6.7.5. Risks and uncertainties in reservoir modelling and development assumptions .. 71

7. Field Development Concept .................................................................................. 72

7.1. Overview ..................................................................................................... 72

7.2. Wells .......................................................................................................... 73

7.2.1. Ekeh-1 and -2H ...................................................................................... 73

7.2.2. Proposed New Well Design ....................................................................... 74

7.2.3. Well Costs .............................................................................................. 74

7.2.4. Completion Design .................................................................................. 74

7.3. Platform and Processing Facilities .................................................................... 76

7.3.1. Early Production Scheme (EPS) ................................................................. 76

7.3.2. Wellhead Platform ................................................................................... 77

7.3.3. Middleton Production Facilities .................................................................. 78

7.3.4. Pipelines & Export ................................................................................... 79

8. Field Development and Operating Costs ................................................................. 80



ix

8.1. Development Capital Expenditure .................................................................... 80

8.1.1. Minimum Development Case – 3 well development ...................................... 80

8.1.2. Low Case 5 – 4 well development .............................................................. 81

8.1.3. Base Case 4 – 5 well development ............................................................. 81

8.1.4. High Case 12 – 6 well development ........................................................... 81

8.2. Field Operating Costs .................................................................................... 82

8.3. Tariff Costs .................................................................................................. 82

9. Economics & Commercial ..................................................................................... 87

9.1. Marginal Fields Fiscal Terms ........................................................................... 87

9.1.1. Production Royalties ................................................................................ 87

9.1.2. Petroleum Profits Tax (“PPT”) .................................................................... 87

9.1.3. Investment Tax Credit (“ITC”) .................................................................. 87

9.1.4. Import Taxes .......................................................................................... 88

9.1.5. Value added Tax (“VAT”) .......................................................................... 88

9.1.6. Niger Delta Development Levy (“NDDC”) .................................................... 88

9.1.7. Education Tax (“ET”) ............................................................................... 88

9.2. Commercial Agreements ................................................................................ 88

9.2.1. MRI Farm-in Agreements to Ekeh .............................................................. 88

9.2.2. Chevron Farm-in Agreement to OML-88. .................................................... 88

9.2.3. Middleton Production Platform Lease and Profit Share Agreement ................... 88

9.2.4. Pennington Terminal Oil Sales Agreement ................................................... 88

9.3. Project Economics ......................................................................................... 89

9.3.1. Minimum Case 1 – 3 well development ....................................................... 90

9.3.2. Low Case 5 – 4 well development .............................................................. 91

9.3.3. Base Case 4 – 5 well development ............................................................. 92

9.3.4. High Case 12 – 6 well development ........................................................... 93

10. Project Risks and Uncertainty Register ................................................................. 94

11. Conclusions ...................................................................................................... 97

12. Abbreviations Used ........................................................................................... 98

Figures Figure 1-1 Probabilistic distribution of Ekeh Oil Resources .............................................. v

Figure 1-1 Ekeh location map offshore Nigeria .............................................................. 1

Figure 1-2 – FPSO based Early Production System ........................................................ 6

Figure 1-3 – Full field development scheme.................................................................. 7

Figure 1-4 - Ekeh Development Schedule (Base Case Development) ................................ 8



x

Figure 2-1: Ekeh base map ........................................................................................ 9

Figure 2-2: Ekeh well correlation, Uro-9 and Iku reservoirs .......................................... 10

Figure 2-3: Ekeh well correlation, Ewinti reservoirs ..................................................... 11

Figure 2-4: Synthetic seismogram Ekeh-1.................................................................. 13

Figure 2-5: Seismic cross line 460 through Ekeh-2H .................................................... 14

Figure 2-6: Seismic line 554 through Ekeh-1 .............................................................. 14

Figure 2-7: Ewinti-2.0 time map ............................................................................... 15

Figure 2-8: Cross plot of two-way time against depth .................................................. 16

Figure 3-1: Pickett analysis from Ekeh-1.................................................................... 18

Figure 3-2 Ekeh-1 Iku-5 and -6 ................................................................................ 19

Figure 3-3: Ekeh-1 Ewinti-2 and Ewinti-2.1 ................................................................ 20

Figure 4-1: Uro-9 depth map ................................................................................... 24

Figure 4-2: Uro-9 RMS amplitude ............................................................................. 24

Figure 4-3: Iku-3 depth map ................................................................................... 25

Figure 4-4: Iku-3 RMS amplitude .............................................................................. 26





Figure 4-9: Ewinti-2.0 depth map ............................................................................. 31

Figure 4-10: Ewinti-2.0 RMS amplitude ..................................................................... 32

Figure 4-11: Ewinti-2.1 depth map ........................................................................... 33

Figure 4-12: Ewinti-2.1 RMS amplitude ..................................................................... 34

Figure 5-1 Iku-3 Reservoir Segments ........................................................................ 36

Figure 5-2 Iku-6 Reservoir Segments ........................................................................ 37

Figure 5-3 Ewinti-2.1 Reservoir Segments ................................................................. 38

Figure 5-4 Decision Tree showing STOIIP outcomes in 14 deterministic cases ................. 41

Figure 5-5 STOIIP Pseudo Cumulative Probability Curve from 14 Deterministic Cases ....... 42

Figure 5-6 Deterministic Cases plotted on the Probabilistic Distribution .......................... 42

Figure 5-7 Minimum Case 3 well Development Scenario Schematic ................................ 43

Figure 5-8 Low Case 4 well Development Scenario Schematic ....................................... 44

Figure 5-9 Base Case 5 well Development Scenario Schematic ...................................... 45

Figure 5-10 High Case 6 well Development Scenario Schematic .................................... 46

Figure 6-1 - Ekeh-1. DST test results ........................................................................ 48

Figure 6-2 – Case 4 Integrated Production System model ............................................ 58

Figure 6-3 - Base Case 4 Production Profile ................................................................ 59

Figure 6-4 Case 4 oil production per reservoir ............................................................ 59

Figure 6-5 - Case 4 field production per liquid stream .................................................. 60



xi

Figure 6-6 – Case 4 alternate Field profile with reduced drawdown ................................ 61

Figure 6-7 – Case 4 alternate profile with reduced drawdown production per reservoir ..... 61

Figure 6-8 - Case 1 Integrated Production System model ............................................. 62

Figure 6-9 - Case 1 Production Profile ....................................................................... 63

Figure 6-10 – Case 1 oil production per reservoir ........................................................ 63

Figure 6-11 - Case 1 field production per liquid stream ................................................ 64

Figure 6-12 - Case 5 Integrated Production System model ........................................... 65

Figure 6-13 - Case 5 Production Profile ...................................................................... 66

Figure 6-14 – Case 5 oil production per reservoir ........................................................ 66

Figure 6-15 - Case 5 field production per liquid stream ................................................ 67

Figure 6-16 - Case 12 Integrated Production System model ......................................... 68

Figure 6-17 - High Case 12 Production Profile ............................................................. 69

Figure 6-18 – Case 12 oil production per reservoir ...................................................... 69

Figure 6-19 - Case 12 field production per liquid stream .............................................. 70

Figure 7-1 Ekeh Location Map .................................................................................. 72

Figure 7-2 Ekeh-2H Well head, xmass tree and conductor ............................................ 73

Figure 7-3 Platform Barge based Early Production System ............................................ 76

Figure 7-4 – FPSO based Early Production System ...................................................... 77

Figure 7-5 – Full field development scheme................................................................ 77

Figure 7-6 Middleton Production Platform ................................................................... 78

Figure 7-7 – Are infrastructure and fields ................................................................... 79

Figure 9-1 JV NPV10 vs Recoverable volumes .............................................................. 89

Figure 9-2 JV NPV10 vs Oil Price ................................................................................ 89

Figure 9-3 Minimum Case JV Net Cash Flow at $100/b ................................................. 90

Figure 9-4 JV Net Cash Flow at $100/b ...................................................................... 91

Figure 9-5 JV Base Case Net Cash Flow at $100/b ....................................................... 92

Figure 9-6 High Case JV Net Cash Flow at $100/b ....................................................... 93

Tables Table 1-1 Summary of Assets before MRI farm-in ........................................................ iv

Table 1-2 Summary of Assets after MRI farm-in ........................................................... iv

Table 1-1-3 TRACS Estimates of Gross and Net Attributable Contingent Resources to MRI. vi

Table 1-1 Ekeh Marginal Field JV Interests ................................................................... 2

Table 1-2 Ekeh Marginal Field Farm-out Overriding Royalty Payments to Chevron NNPC ..... 2

Table 1-3 Midway Farm-in Payments ........................................................................... 3

Table 2-1: Reservoir formation tops and hydrocarbon contacts ..................................... 12

Table 3-1 Petrophysical averages ............................................................................. 21

Table 4-1: Uro-9 GRV range and likeliest reservoir parameters ..................................... 23



xii

Table 4-2: Uro-9 GIIP volumes ................................................................................. 23

Table 4-3: Iku-3 GRV range and likeliest reservoir parameters ..................................... 26

Table 4-4: Iku-3 STOIIP volumes ............................................................................. 26


Table 4-6: Iku-5 GIIP volumes ................................................................................. 28


Table 4-8: Iku-6 GIIP volumes ................................................................................. 30

Table 4-9: Iku-6 STOIIP volumes ............................................................................. 30

Table 4-10: Ewinti-2.0 GRV range and likeliest reservoir parameters ............................. 32

Table 4-11: Ewinti-2.0 GIIP volumes ......................................................................... 32

Table 4-12: Ewinti-2.0 STOIIP volumes ..................................................................... 32

Table 4-13: Ewinti-2.1 GRV range and likeliest reservoir parameters ............................. 34

Table 4-14: Ewinti-2.1 GIIP volumes ......................................................................... 34

Table 4-15: Ewinti-2.1 STOIIP volumes ..................................................................... 34

Table 4-16 Ekeh Field Probabilistic STOIIP Summary ................................................... 35

Table 5-1 Iku-3 Deterministic STOIIP Segments ......................................................... 36

Table 5-2 Iku-6 Deterministic STOIIP Segments ......................................................... 37

Table 5-3 Ewinti-2.1 Deterministic STOIIP Segments ................................................... 38

Table 5-4 Ewinti-2.0 Deterministic STOIIP Segments ................................................... 39

Table 5-5 Summary of Ekeh deterministic STOIIP volumes ........................................... 39

Table 6-1 Range of oil recovery factors ...................................................................... 49

Table 6-2 - Probabilistic STOIIP and Recoverable Oil (MMstb) ....................................... 49

Table 6-3 - Range of gas recovery factors .................................................................. 49

Table 6-4 - Probabilistic GIIP and Recoverable Gas (Bscf) ............................................ 49

Table 6-5 - Lab PVT analysis results Iku-3 ................................................................. 50

Table 6-6 – Surface sample measured PVT Ewinti 2.1 and Iku-6 ................................... 51

Table 6-7 - Reservoir pressure estimation in Ekeh field. ............................................... 51

Table 6-8 - Horizontal permeability estimation ............................................................ 51

Table 6-9 – Calculated well PI for main development targets ........................................ 52

Table 6-10 – Initial natural flowing rates vs. FWHP, deviated well, initial res conditions .... 53

Table 6-11 – Initial natural flowing rates vs. FWHP, horizontal well, initial res conditions .. 53

Table 6-12 MBal reservoir input parameters ............................................................... 55

Table 6-13 – Developed STOIIP values within MBAL models ......................................... 55

Table 6-14 – Sandface drawdown constraints applied to forecasts ................................. 56

Table 6-15 Summary of GAP model recoverable volume scenarios ................................. 57

Table 6-16 – Case 4 recoverable volumes per reservoir unit to end-2030 ....................... 58

Table 6-17 - Case 1 recoverable volumes per reservoir unit to end-2030 ........................ 62

Table 6-18 - Case 5 recoverable volumes per reservoir unit to end-2030 ........................ 65



xiii

Table 6-19 – Case 12 recoverable volumes per reservoir to end-2030 ............................ 68

Table 7-1 – Completion specification for Ekeh production wells ..................................... 75

Table 8-1 Minimum Case 1 – 3 well development CAPEX and OPEX Forecast ................... 83

Table 8-2 Low Case 5 – 4 well development CAPEX and OPEX Forecast .......................... 84

Table 8-3 Base Case 4 – 5 well development CAPEX and OPEX Forecast ......................... 85

Table 8-4 High Case 12 – 6 well development CAPEX and OPEX Forecast ....................... 86

Table 9-1 Royalty Rates .......................................................................................... 87

Table 9-2 Investment Tax Credit Rates ...................................................................... 87

Table 9-3 Minimum Case NPV10 and Cashflow Summary ............................................... 90

Table 9-4 Low Case NPV10 and Cashflow Summary ...................................................... 91

Table 9-5 Base Case NPV10 and Cashflow Summary ..................................................... 92

Table 9-6 High Case NPV10 and Cashflow Summary ..................................................... 93


TRACS International Consultancy Limited 18th October 2011 1

1. Introduction This Competent Person’s Report (CPR) provides an independent assessment of the Contingent Resources of the Ekeh Field, Nigeria. Midway Resources International (MRI) is currently concluding negotiations on definitive agreements to acquire a 40% interest in Ekeh in return for funding the appraisal and development of the field.

1.1. Licences and Agreements

Ekeh Field is located in the Chevron-operated block OML88 offshore Nigeria. Ekeh was discovered by exploration well Ekeh-1, drilled by Texaco in 1986/7. The oil and gas discovery was not developed at the time, and was subsequently awarded to Movido Exploration and Production Ltd (Movido) in 2003 under the 2001 Marginal Fields Allocation Round. Under the Marginal Fields terms, Chevron and NNPC retain their licence interests in OML88, but allow Movido to develop the marginal field under a farm-in agreement, dated 18th March 2004, under which the licence holders will receive an overriding royalty payment from production.

Over the period 2005-2008 Movido partially farmed out 40% of their 100% interest in Ekeh to Nigerian companies DWC Supplies (Nigeria) Ltd (20% interest and technical advisor) and SLJ Oil and Gas Nigeria Ltd (20% interest and financial advisor) in return for funding the development of Ekeh. Movido drilled a development well (Ekeh-2H) in 2005 with the intention of developing the field with a wellhead platform tied back to production facilities at Chevron’s nearby Middleton Field. However the well suffered severe mechanical problems and was not successfully tested, and notwithstanding further re-entry in 2008 and 2010, was not able to be put into production. Development was then suspended due to lack of available finance. The Ekeh-2H well remains shut-in (but not temporarily abandoned) and in its current mechanical state is considered a liability until it is plugged and abandoned.

Madu

Anyaia

Sengana

Okubie

Middleton

Pennington Field

Pennington Terminal

Funiwa

Apoi

Bilabri‐Oribiri

EH

Bol

Chioma

Akarino

Ato

EKEH

27.5 km 10 ¾” pipeline

20.6 km 6 5/8” pipeline

NIGERIA

Key

Pipeline

Oil Field

Gas Field

Figure 1-1 Ekeh location map offshore Nigeria



It is now proposed that MRI will acquire the interests of DWC and SLJ and become the technical and financial advisor, whilst Movido remains as operator to the Joint Venture. MRI will fund the development of the field to an agreed limit of $100 million. Subject to the completion of the planned transaction, MRI will acquire a 40% interest in Ekeh Field.

The farm-out of Ekeh Field by Chevron and NNPC was valid for an initial period of 60 months from the effective date of 18th March 2004, but renewable subject to approval by the Department of Mineral Resources (DPR) for as long as the underlying OML88 lease lasts. DPR approval was received for extending the marginal field rights for 4 years from March 14 2011. As OML88 remains on foot, the Farm-out extension is expected to be a formality although it will be a condition precedent to the acquisition.

Before MRI Farm-in After MRI farm-in

Movido Exploration & Production Ltd 60% (Op) 60% (Op)

DWC Supplies (Nigeria) Ltd 20% -

SLJ Oil and Gas Nigeria Ltd 20% -

Midway Resources International - 40%

Table 1-1 Ekeh Marginal Field JV Interests

Likewise, the Middleton Production Platform Lease Agreement will need to be novated and extended as part of the MRI farm-in process. Recent mapping of the Ekeh Field shows that it most likely extends beyond the boundaries of the previously agreed marginal field area. These boundaries may be adjusted on the basis of technical evidence to cover all reservoirs discovered by Ekeh-1 and any additional accumulations defined within the area and depth (Ekeh 1) co-ordinates.

The existing farm-out agreement with Chevron provides for Chevron and NNPC to receive the following overriding royalties:

Oil Production bpd Royalty Rate Gas Production MMscfpd Royalty Rate

0-2000 2.5% 0-20 0%

2000-5000 3% 20-50 2.5%

5000-10000 5.5% 50-100 3.5%

10000-15000 7.5% >100 5%

>15000 7.5%

Table 1-2 Ekeh Marginal Field Farm-out Overriding Royalty Payments to Chevron NNPC

Under the existing, but now expired Middleton Production Platform Lease Agreement the Ekeh partners would pay a capacity charge of $1.75 per barrel for the use of the Middleton Production Platform. The capacity provided was agreed to be 7000 bpd for the first 6 months ($12,250/d), followed by 10,000 bpd ($17,500/d) thereafter. These figures are subject to inflation corrections and renegotiation, and will be settled prior to close of the acquisition. MRI is undertaking a full integrity and engineering inspection of the platform prior to signing of the Definitive Agreements for acquisition; and such inspection will inform both the terms of the acquisition and any subsequent platform refurbishment and utilisation as part of the Full Field Development plan.



1.1.1. Midway Farm-in Agreement

It is proposed that MRI will acquire a 40% interest in Ekeh Field from DWC and SLJ in return for the following payments totalling $189.5 million:

Allocation Amount $MM

Comment

Development 100 For Development costs, with any underspend distributed between MRI (18.975%), Movido (18.975%), DWC (37.95%) and SLJ (24.1%). These costs will be reimbursable in priority to all other claims on JV revenue, with interest to MRI, from JV production revenues.

SLJ JV Loan Account with AIB

40 MRI will pay off SLJ’s Loan Account with Anglo Irish Bank which was used to fund previous Ekeh drilling. This amount will be reimbursable with interest to MRI from production revenues.

Historical Working Capital

6.5 MRI will reimburse the JV partner’s previous expenses on Ekeh. This amount will be reimbursable in priority to all other claims on JV revenue, with interest to MRI, from JV production revenues.

MRS JV Loan Account

6.5 MRI will pay off (Movido shareholders) MRS’s Loan Account which was used to fund previous Ekeh drilling. This amount will be reimbursable in priority to all other claims on JV revenue, with interest to MRI, from JV production revenues.

Farm-in consideration

31.1 MRI will pay $23.3 million cash to the vendors, and $7.8 million out of MRI’s production revenues as a farm-in premium.

Performance Bonuses

4.4 Movido will receive $11 million in production bonuses from project revenues, of which MRI will contribute 40%.

Consultancy 1.0 MRI will, in return for actual consultancy services in Nigeria and elsewhere, pay $1 million consultancy fees to Michael Barnes over a 5 year period.

Table 1-3 Midway Farm-in Payments

1.2. Exploration History

The Ekeh Field was discovered by Texaco with Ekeh-1 drilled in 1986. Ekeh Field is located in 40 ft water depth 7 km from the Middleton Field in the Chevron-operated offshore block OML 88, offshore Nigeria.

Ekeh-1 was drilled to 11,410 ft MD (measured depth) on December 15, 1986 when it encountered mechanical problems. The well was side tracked at 9,473 ft md and drilled to 9,990 ft MD. Drilling was discontinued on December 31, 1986 because of anticipated further mechanical problems. Five hydrocarbon bearing reservoirs were present between 4,250 ft MD (-4,171 ft TVSss) and 5,236 ft MD (-5,022 ft TVDss), namely; the Iku-3, Iku-5, Iku-6, Ewinti 2.0 and Ewinti-2.1 sands. A total of 25 vertical feet of net gas, 156 vertical feet of net condensate and/or oil and 97 vertical feet of net oil sands were encountered. Sands encountered below Ewinti 2.1 were water-wet.



A 17 hr DST on the Ewinti-2.1 sands (-4,929 ft TVDss – 5,021 ft TVD ss) yielded a maximum 2,192 BODP of 35.6 API crude at 660 psig FWHP on a half inch choke. Average GOR was 420 SCF/STB with gas S.G of 0.75. The PVT properties were reported from field measurements of surface separator samples. Post testing Ekeh-1 was plugged and abandoned (P&A’d) with the casing cut below the mudline.

In 2003 Movido acquired the right to develop the Ekeh field under the Marginal Fields Allocation Round. In 2005 Movido initiated the development by drilling Ekeh-2H, designed as a dual completion production well with the main horizontal completion in the Ewinti-2.1 reservoir and a secondary completion in the Iku-6. Logs identified hydrocarbons in the same 5 reservoirs as Ekeh-1, plus indications of hydrocarbons in the shallower Oru-9 sand.

Before running the 9 5/8” casing an MDT was run and a bottom hole sample successfully acquired from the Iku-3 reservoir at 4,378 ft MD (-4,157 ft TVDss). Laboratory PVT analysis showed a 25.2 °API (stock tank) oil with separator GOR of 245 scf/stb, gas S.G. of 0.65 and crude viscosity at reservoir conditions of 3.25 cP. Reservoir pressure was 1,844 which indicates a normally pressured reservoir.

The horizontal section was completed with a pre-drilled liner (PDL) in open hole; however multiple problems occurred in the completion of the well. The 8.5” open hole section was drilled from 6,059 ft MD to 6,974 ft MD (915 ft MD). The 7” PDL was run to 6,224 ft MD before hole conditions halted further running, therefore only 165 ft of the open hole section was lined (6,059 ft to 6,974 ft MD). The well was drilled with water based mud, which is thought to be a contributory factor to problems caused by swelling shales which caused the 7” liner to get stuck in the hole. The well was perforated in the Iku-3 reservoir (9ft from 4939 - 4948 ft MD) and a dual completion run with the Short Sting on Iku-3 and the Long String on Ewinti 2.1. On cessation of completion activities the well was suspended without successful testing.

Ekeh-2H was re-entered for testing in August-December 2008. The maximum recorded rate for the Iku-6 (short string) on a 32/64” choke was 250 BOPD over more than a week’s testing. The Ewinti 2.1 reservoir (long string) produced during 44 hr flowing test an average of 1,050 BOPD of 28.5 API crude at 210 psig FWHP on a 32/64” choke. Average GOR was 250 SCF/STB with gas S.G of 0.7. The PVT properties were reported from field measurements of surface separator samples. It should be noted that the recorded fluid properties for the reservoir from this test are substantially different from those reported from the Ekeh-1 test in Ewinti 2.1 reservoir. A lower API less gassy oil would be more viscous at reservoir conditions and therefore have a considerably lower Productivity Index (stb/d/psi). Resolution of the fluid PVT properties within Ewinti 2.1 (and Iku-6) is a key uncertainty that requires resolution.

It should be noted that sand production was observed during the test of Ekeh-2H from both the long and short strings. This involved sand plugs in the tubing and free sand produced to surface indicating both reservoirs are highly unconsolidated. No sand control was run on the either section. As the formation is very unconsolidated is therefore likely that the open hole section of the well (750 ft from 6,224 ft to 6,974 ft MD) suffered wellbore collapse. As no sand control was run, it is quite possible that the 165 ft PDL section also became filled with some degree of formation sand.

Regardless of crude property, the surface flow rates achieved from the well test in Ekeh-2H the stated flowing wellhead pressures suggests a high degree of skin damage, even with a limited effective well length of 165 ft. The Ewinti-2.1 reservoir section appears to have been impaired by high viscous mud filtrate invasion into formation pore spaces and possible contact with reactive shale(s). HEC (Hydroxyethylcellulose) and other components of the viscous pill that was circulated across the open hole exacerbated this damage mechanism. The HEC was not immediately cleaned out with acid after initial completion operations making it unlikely that permeability could be restored.



The most recent activity on the Ekeh-2H well occurred in Feb 2010 when a coil tubing clean out was attempted. During the attempted clean-out a mixture of sea water, diesel and nitrogen was pumped. At the end of the intervention activity surface pressure on the SCSSV was bled off to actuate a tubing close. No kill weight brine was circulated and no physical plugs were set in any of the nipples or SCSSV. The well remains unsuspended.

It should be noted that the surface conductor has at some point in time been hit by a vessel, resulting in the conductor being bent to a 15 degree angle. The well is now thought irreparable and unusable for safe operations. It is unknown if the coil tubing intervention occurred before or after the incident which bent the conductor, but a number of heavy ships were involved in the workover.

Given that Ekeh-2H well is not suspended and requires temporary abandonment at the very least; and more likely plug and abandonment, it should be considered a liability in its current state. The well should be abandoned at the earliest opportunity. It is advised that this activity is conducted when the rig is brought in to drill the Appraisal well and the first new horizontal development well.

1.3. Appraisal Requirements

The Field Development Plan prepared by Movido in 2005 assumed a 3 well development supported by a 5-slot minimum facilities wellhead platform at Ekeh tied back to production facilities on the Middleton Production Platform. It assumed, incorrectly as it turned out, that Ekeh-2H would produce sufficient revenue from barge based temporary production facilities to obviate the need for additional capital for further wells and development. Evaluation work performed by MRI shows that there is still considerable uncertainty in the size of Ekeh Field, which could require 3-7 development wells, and that further appraisal is required before the development can be optimised. The key uncertainties are:

1. The presence of oil in the northwest extension of the Ekeh structure;

2. The depth of the OWC, and oil column thickness in the main reservoir (Ewinti-2.1 sand);

3. Reservoir and fluid qualities, and well productivity.

MRI propose to appraise the field by:

1. Drilling an appraisal well to confirm the presence of oil in the northwest extension of the structure, and to try to confirm the OWC in the Ewinti-2.1 main reservoir;

2. Obtaining fluid and core samples;

3. Performing long term production tests to gather enough information to demonstrate optimised economic levels of sustainable production and reserves and the optimal facilities design.

It is proposed to perform long term production testing of 2 wells (the northwest appraisal well and a redrill of Ekeh-2H in the Ewinti-2.1 main reservoir) via an Early Production Scheme. After 6 months of production from these 2 wells to a temporary barge based production facility, the full field development plan will be optimised and settled. The full field development plan will then be executed with facilities expected to be commissioned into production at approximately 12 months from the final investment decision point.



1.4. Development Philosophy The philosophy applied by MRI is to appraise and develop the field in up to 4 phases:

Phase 1 (Appraisal & EPS): Drill 1 Appraisal well in NW Ekeh and 1 Development well in the Ewinti-2.1 Formation in Ekeh main field, and put these wells on production via a Floating Production Storage and Offloading (FPSO) vessel or production testing barge (both requiring offloading to shuttle tanker) for six (6) months to determine reserves and production potential. Figure 1-2 shows a schematic for the FPSO Early Production System (EPS) variant. It is recommended that Ekeh-2H is plugged and abandoned with the rig brought in to drill the first two wells.

Phase 2 (Development and EPS): Confirm optimal facilities and wells requirements, take final investment decision, procure, construct and install a production facility for Ekeh, and reinstate or replace the topsides of Middleton Production Platform. This phase would last for twelve (12) months, during which oil production would continue using the EPS. Depending on the appraisal results, the development concept could involve tie back to the Middleton Production Platform (current base case), use of a new production platform or continuation of production with an FPSO, or early cessation of activity.

Phase 3 (Main Production): Drill additional wells from the newly installed Ekeh wellhead platform, with production routed through the permanent production facilities. Figure 1-3 shows a schematic of the favoured full field development scheme with Ekeh wellhead jacket installed, tie back to the existing Middleton platform and export to Pennington via existing infrastructure.

Phase 4 (Further Development Options): Depending on results, a second phase development could proceed, based on further appraisal on undeveloped reservoir zones, recompletions on unproduced zones, sidetracks of existing wells or new development wells.

Figure 1-2 – FPSO based Early Production System



Figure 1-3 – Full field development scheme

1.5. Project Schedule

A high level Project Schedule is shown in Figure 1-4 for the base case development. It would see first oil to the EPS in Jan-13, first oil to Middleton facility Nov-2015 and the Ekeh field on Plateau with four to five (4-5) producers by Apr-2015 (a successful Appraisal 1 well counted as one of the producers). TRACS/AGR views this project delivery schedule as fairly aggressive with some chance of slippage. To allow schedule delivery a number of activities must run concurrently and detailed work must begin on the Project Execution Plan, the App-1 and Dev-1 well proposals and the Ekeh-2H abandonment proposal 2011. The schedule also assumes that Final Investment Decision will be made after completion of Basis of Design and not FEED (which is more typical). The schedule is based upon the assumption that i) the Middleton Production Platform will require some upgrade, but that the majority of the existing equipment can be re-utilised ii) Movido has already progressed some engineering work on the development and iii) all commercial matters relating to the licence and Midways participation within the license are resolved in the near term. Early partner commitment and very detailed project management are key to schedule delivery. To date a suitable (and available) EPS offshore facility has not been identified and market search to identify such should be undertaken immediately.



2011

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2

DOCUMENT: Field Development Plan

DOCUMENT: Preliminary Project Execution Plan

DOCUMENT: Basis of Design

DOCUMENT: Well Proposal

DOCUMENT: Project Spec

DOCUMENT: Project Execution Plan

Order Long Lead Items Phase 1 drilling

MILESTONE: Select and Contract EPF

Mob Rig

Install Drilling Template

Drill Apraisal 1

Drill Dev 1

Abandon Ekeh‐2H

Mob EPF

Commission EPF

MILESTONE: First Oil EPF

EPF Production

MILESTONE: FID on Full Field Development

FEED Tender

MILESTONE: FEED Tender & Award

Order Critical Path Long Lead Items

Deliver Critical Path Long Lead Items

FEED

Order Remaining Long Lead Items

Deliver Remaining Lead Items

Bid packages & tender

MILESTONE: Contractor Bid Award

Detailed Eng. for Midltn upgrade and Ekeh tie‐back

Mobilise Contractors

Upgrade of Middleton Facilities

Installation of pipelines

Installation of Ekeh Jacket

Commission facilities

MILESTONE: First Oil Middleton

Mob Rig

Drill Dev 2

Drill Dev 3

Drill Dev 4

Connect new wells

MILESTONE: Ekeh Field on Plateau

2012 2013 2014 2015

Figure 1-4 - Ekeh Development Schedule (Base Case Development)

1.6. Key Risks and Uncertainties

Key project risks and mitigation activities are summarised in the Eken Project Risk Register in Section 11 of this report. Risks are reported in the categories of Technical, Economic, Commercial and Operational risk. Against each identified risk TRACS/AGR has independently summarised the impact or consequence should such risks be realised, the commercial impact (at a project level) and identified risk mitigation measures where relevant.



2. Geology & Geophysics

2.1. Seismic Interpretation

2.1.1. Seismic /well data base

A 3D seismic survey covering 30 km2 was provided for the interpretation of the Ekeh Field (Figure 2-1). The seismic data provided extends beyond the 14.59 km2 Marginal Field licence area, enabling an extension of the field to the NW of Ekeh-1 to be mapped.

Figure 2-1: Ekeh base map

At the depth of the reservoirs the seismic data is of moderately to good quality and sufficient to provide confidence in the accuracy of the picked reservoir horizons.

Well header information, deviation surveys, well logs and formation tops were supplied for both wells. In addition, a check-shot survey was provided for Ekeh-1 and an end of well report for Ekeh-2H. The main problem with the well data was the deviation survey for Ekeh-1. This started at 4931 ft where the well inclination was already at 34.75 degrees. Unfortunately, no information was provided on the kick-off point and build-up to reach this inclination.



A processed deviation survey produced by Schlumberger calculated a build-up of inclination from the seabed. This was thought highly unlikely, especially as it showed that the well would be located on a downthrown fault block with respect to Ekeh-2H. A petrophysical averages spreadsheet provided for Ekeh-1 gave measured and TVDSS depths for the primary reservoirs. This showed differences of over 200ft in TVDSS for the reservoir intervals compared with the Schlumberger deviation survey. As it was believed that the measured/TVDSS relationship in the petrophysical averages spreadsheet was correct, the upper part of the Ekeh-1 deviation survey was adjusted to match this relationship.

2.2. Reservoir correlation

Figure 2-2: Ekeh well correlation, Uro-9 and Iku reservoirs

Well logs were used to correlate the reservoirs of the two Ekeh wells. This established that there are six sandstone reservoirs that contain hydrocarbons. From previous work these have been named, Uro-9, Iku-3, Iku-5, Iku-6, Ewinti-2.0 and Ewinti-2.1. They are all present in Ekeh-2H and five are present in Ekeh-1. As the bottom hole positions of the wells are close (300-700m), there is generally a very good correlation of the reservoirs. This can be clearly seen in the Iku-5 and Iku-6 reservoirs (Figure 2-2). The major difference occurs above the base of the Iku-3 reservoir. This reservoir is much thinner in Ekeh-1 due it being displaced by a fault. This fault has also removed the Uro-9, seen in Ekeh-2H, from Ekeh-1. The Ewinti-2.0 reservoir shows a good correlation



between the wells. However, below the top of the Ewinti-2.1 the Ekeh-2H well is drilled horizontally so no further correlation is possible (Figure 2-3).

Figure 2-3: Ekeh well correlation, Ewinti reservoirs

The above correlation was used to refine the formation top depths for the six reservoirs, and ascertain the hydrocarbon type and contacts present. The results of this correlation, the hydrocarbon column limits and contacts found are given in the table below.



Reservoir Ekeh-1 Ekeh-2H

Top MD/

TVDSS ft

Base MD/

TVDSS ft

Hydrocarbon

Type & Contact

Top MD/

TVDSS ft

Base MD/

TVDSS ft

Hydrocarbon

Type & Contact

Uro-9 Absent Absent Faulted out 4139.0

-3943.2

4194.8

-3993.8

Gas?

GDT -3993.8

Iku-3 4253.0

-4172.3

4271.5

-4190.0

Faulted top

Oil ODT -4190

4328.2

-4112.5

4478.1

-4241.6

Oil

OWC -4193.8

Iku-5 4477.0

-4381.2

4510.1

-4409.4

Gas

GDT -4409.4

4715.0

-4430.6

4755.2

-4460.6

Gas

GDT -4447.2

Iku-6 4554.0

-4446.9

4696.2

-4568.2

Gas

GDT -4568.2

4811.0

-4501.6

5005.6

-4633.0

Gas & Oil

GOC -4570.0

OWC -4615.0

Ewinti-2.0 5067.0

-4880.5

5097.0

-4905.2

Gas

GDT -4905.2

5748.0

-4950.5

5882.9

-4973.2

Oil

OUT -4950.5

ODT -4971.0

Ewinti-2.1 5124.5

-4928.0

5236.5

-5020.7

Gas & Oil

GOC -4942.1

ODT -5020.7

6086.5

-4984.8

Not penetrated

Oil

ODT -4990.0

Table 2-1: Reservoir formation tops and hydrocarbon contacts

Note:

ODT = deepest oil seen in well by reservoir

GDT = deepest gas seen in well by reservoir

OUT = shallowest oil seen in well by reservoir

GOC = gas oil contact

OWC = oil water contact



2.3. Horizon interpretation

As a sonic log, density log and check-shot survey were provided for Ekeh-1, a synthetic seismogram was constructed to tie formation tops to the seismic data (Figure 2-4). Generally the reservoir sands had lower velocity and density than the surrounding shales and as a result, the top of each reservoir gave a negative seismic impedance contrast. The synthetic seismogram showed this was represented on the seismic data as a trough. Unfortunately it was not possible to tie the top Uro-9 and Iku-3 reservoirs in Ekeh-1 due to their removal by a fault. However, by copying the check-shot data from Ekeh-1 to Ekeh-2H it was possible to pick the top of these reservoirs on the seismic data (Figure 2-5).

Figure 2-4: Synthetic seismogram Ekeh-1

The following horizons were picked and structure maps of the reservoirs were created and the range of gross rock volume was evaluated for each:

1. Top Uro-9 2. Top Iku-3 3. Top Iku-6 4. Top Ewinti-2.0 5. Base Ewinti-2.1

In addition, a deeper horizon was picked (Lower Ewinti) to ascertain whether the deeper water bearing sands were within structural closure at the Ekeh-1 well location. The interpretation showed that Ekeh-1 was drilled into a tilted horst with the well designed to track the up-dip fault (Figure 2-5 and Figure 2-6).



Figure 2-5: Seismic cross line 460 through Ekeh-2H

Figure 2-6: Seismic line 554 through Ekeh-1



The above horizons were picked over the area of the 3D seismic grid on an 8x8 grid. Faults were picked on the interpreted lines and correlated with assigned names. These were used to construct fault polygon sets for each horizon. Where the quality of the seismic data was sufficient, the grid of picked lines was used to seed the auto-picking algorithm so that horizon values were present on all lines. Time horizons were gridded, contoured and a set of time maps produced. These show the trap is located on the foot wall of a tilted horst block. The crest is at the southeast end where a major east-west trending fault intersects a southeast trending fault. A third southeast trending fault intersects the east-west fault on the southwest side of the discovery further constraining the trap. The final trap element is bed dip to the northwest (Figure 2-7).

Figure 2-7: Ewinti-2.0 time map



2.4. Depth conversion

The depth conversion for the seismic horizons was based on the check-shot survey from Ekeh-1 and time depth relationships from the interpreted horizons. The steepening of the curve shown on the cross plot of two-way time verses depth indicates an increasing velocity with depth due to sediment compaction caused by increasing depth of burial (Figure 2-8). To account for this a V0, k to base of layer depth conversion method was used. Employing the Excel solver utility, a best parameter fit was obtained as given below:

V0 = 5898.2

K = 0.31781

Figure 2-8: Cross plot of two-way time against depth

The comparison with the data and the V0, k velocity model above shows a close match thereby giving confidence in the method. Each of the interpreted reservoir horizons were depth converted in turn using the V0, k equation as shown below:

Depth = V0/k*(EXP(k*TWT/2)-1)

Where Depth = feet below MSL

TWT = two-way time in seconds

Residual grids were added to these initial depth grids to accurately tie the maps to the formation tops in the wells. To enable accurate estimates of gross rock volume to be made, the remaining top and base reservoir surfaces were produced by isopach addition.



3. Petrophysical Analysis

Petrophysical analysis used the Interactive Petrophysics (IP) software, both Ekeh-1 and Ekeh-2H wells were loaded as LAS files while deviations where taken from the Kingdom project. Both wells are deviated, Ekeh-1 has a maximum deviation of 35° while Ekeh-2H is horizontal, with a maximum deviation of 101°.

The analysis followed the workflow outlined below:

1. Data loaded from LAS files

2. Curves checked for depth errors by using the GR as the definitive on depth log

3. Volume of clay calculated

4. Porosity calculated

5. Estimation of Permeability using 3 models

6. Water saturation calculated

7. Petrophysical Sums and averages derived from the calculated logs.

3.1. Data loading and edits

Well log data was loaded direct from the supplied LAS files, each well has a simple set of triple combo log curves covering the reservoir section, comprising of Gamma ray, deep resistivity, density and neutron.

All logs in both wells are on depth when compared to the Gamma ray, no depth shifting was required.

The high deviation angle of Ekeh-2H causes severe bed boundary effects on the resistivity log to occur. Re-modeling the resistivity log to correct for these effects is sometimes possible, but time consuming and requires a good understanding of the borehole environment. The limited data availability in Ekeh-2H precludes resistivity re-modelling, but where the effect is significant the resistivity has been manually edited by clipping the log to an average value. The effect is most pronounced in the Ewinti-2.1 formation of Ekeh-2H.

Fluid effects are pronounced on both the density and neutron logs, the density log has been corrected for fluid effect using fluid densities of gas = 0.3 g/cc, oil = 0.8 g/cc and brine of 1.1 g/cc, and is corrected back to a 100% brine log.

The fluid density is a mix of the above densities using a provisional Sw curve, and is substituted into the density curve as follows.

RHOB-(((1-AGR:Swarch)*fluiddensity)*PHIT_raw)+(((1-AGR:Swarch)*1.1)*PHIT_raw).

The resulting density curve is free of hydrocarbon fluid effects.

3.2. Volume of clay

As both the density and neutron have significant fluid effects, the volume of clay has been calculated from the gamma ray alone using a simple linear two-end point method in each formation.

In each formation the reservoir tends to be clean at the top with a overall increasing volume of clay with depth. Clean sand has an average Gamma ray of between 30 to 60 Gapi, while shale has a range between 90 to 120 Gapi dependent upon formation.



3.3. Porosity

Porosity was calculated from the brine corrected density log using a grain density of 2.66 g/cc and a brine density of 1.1 g/cc. Porosities are excellent with all formations having porosities in the high 20’s to low 30’s.

3.4. Water saturation

Water saturation was calculated using Archie, Rw was derived from Pickett analysis in the multiple water legs from Ekeh-1 and is taken as 0.136 @ 183 °F, m is taken as 1.74, as this provides the best fit line in the Pickett analysis. A and n are taken as 1 and 2 respectively.

Figure 3-1: Pickett analysis from Ekeh-1

Saturations in all formations that are hydrocarbon bearing are good, with all formations having water saturations below 50%.



3.5. Permeability

Three permeability models have been generated to assist with production modelling, the models selected were Biggs, Timur and formation factor.

Both Biggs and Timur are well established and are based on core analysis, the parameters used are porosity and irreducible water saturation. Formation factor is based on the F exponent from calculation of tortuosity. The formation factor model tends to be the most optimistic, while Timur is the most pessimistic.

Formation factor permeability = 7*10^6/(F^4.5), where F = 0.62/(PHIE^m)

Biggs Permeability = 62500*(PHIE^6)/(Sw irr^2)

Timur permeability = 3400*(AGR:PHIE^4.4)/(Sw irr^2)

Figure 3-2 Ekeh-1 Iku-5 and -6



Figure 3-3: Ekeh-1 Ewinti-2 and Ewinti-2.1



Reservoir Parameter Reservoir average Pay average

Ekeh-1 Ekeh-2H Average Ekeh-1 Ekeh-2H Average

Uro-9

Gross ft 57.0 57.0 Net ft 44.2 41.0 Net/gross 0.776 0.776 0.720 0.720 Porosity 0.301 0.301 0.305 0.305 Sw 0.337 0.337 0.319 0.319

Iku-3

Gross ft 17.8 129.1 17.8 129.1 Net ft 8.0 94.0 5.0 58.5 Net/gross 0.451 0.728 0.694 0.282 0.453 0.432 Porosity 0.299 0.325 0.323 0.32 0.312 0.313 Sw 0.477 0.543 0.538 0.423 0.323 0.331

Iku-5


Iku-6


Ewinti-2.0


Ewinti-2.1

Gross ft 92.7 92.7 Net ft 71.0 69.0 Net/gross 0.766 0.766 0.744 0.838 0.791 Porosity 0.26 0.260 0.26 0.297 0.279 Sw 0.263 0.263 0.255 0.094 0.175

Table 3-1 Petrophysical averages

Reservoir cut-offs:

Effective porosity less or equal to 0.1

Clay volume greater or equal to 0.5

Pay cut-offs:

Effective porosity less or equal to 0.1

Clay volume greater or equal to 0.5

Water saturation greater or equal to 0.5



Note:

For calculation of averages, gross and net intervals were calculated using true vertical thickness.

Reservoir and pay net/gross ratios were calculated by sum of net intervals/sum of gross intervals.

Reservoir and pay porosity averages are net rock weighted.

Reservoir and pay water saturation averages are net pore weighted.

The likeliest input parameters used for calculation of GIIP and STOIIP were selected as follows:

For fully hydrocarbon saturated reservoirs; the net pay averages of net/gross ratio, porosity and water saturation were selected.

For partially hydrocarbon saturated reservoirs; reservoir averages of net/gross ratio and porosity were selected. For water saturation the net pay averages was used.



4. Estimation of in-place hydrocarbon volumes

The range of GIIP and STOIIP was estimated probabilistically for each reservoir using the Monte Carlo method. Gross rock volume (GRV) was estimated using top and base reservoir surfaces produced from the depth converted seismic horizons and the subsequent intervening surfaces. Polygons were used to constrain the area to the fault block where hydrocarbons have be discovered. If a GOC or OWC was obtained from a well, these were used but if not, a range of GRV was calculated using a low side limit based on hydrocarbon columns seen in wells and a high side case based on structural spill points seen on the relevant top reservoir maps. The licence boundary in the current farm-out agreement shows that hydrocarbons for all the reservoirs are likely to extend outside the area to the northwest. The licence area can be extended subject to technical evidence and agreement with Chevron and NNPC. Therefore GRVs were calculated for the full extent of the discovery and for the area within the licensed area. In-place hydrocarbon volumes were forecast for the complete field area and the volumes within the licensed area were calculated based on the relationship of total GRV to licence area GRV.

The range of reservoir properties used for the input to the GIIP and STOIIP estimation were obtained from petrophysical averages calculated from the wells. A brief description of each reservoir together with the top reservoir structure map, input parameters and forecast of in-place hydrocarbons is given in the following sections. In addition, RMS amplitude maps were produced for each reservoir interval to aid understanding of the likely extent of each accumulation.

4.1. Uro-9

This is the shallowest reservoir where hydrocarbons have been discovered in Ekeh. Due to the combination of faults that form the trap, it is only seen in Ekeh-2H. It has been interpreted to be faulted out by the northeast bounding fault in Ekeh-1 (Figure 4-1). It is believed from the neutron-density crossover on the petrophysical analysis that the hydrocarbons in this reservoir are gas. No hydrocarbon water contact was seen in this reservoir so a range between the lowest seen gas and the spill point of the structure was used. The amplitude map of this reservoir (Figure 4-2) shows a strong anomaly that extends to the northwest to between the -4000 to -4030ft TVDSS contour. This provides confidence in the GRV assumption, as it matches the range of GWC used in the GRV calculation (Table 4-1).

Shallow GWC

Deep GWC

GRV P90 Total/ License

GRV P10 Total/ License

N/G PHIE Sw GEF

m3*106 m3*106 fraction fraction fraction

-3994.0 -4,033.0 6.80 6.48

20.07 8.72 0.720 0.305 0.319 125.0

Table 4-1: Uro-9 GRV range and likeliest reservoir parameters

Area GIIP bcf

Mean P90 P50 P10 Structure 8.4 4.2 7.6 13.8 Licence 5.4 4.0 5.3 6.0

Table 4-2: Uro-9 GIIP volumes



Figure 4-1: Uro-9 depth map

Figure 4-2: Uro-9 RMS amplitude



4.2. Iku-3

The Iku-3 reservoir is much thicker in Ekeh-2H (129.1ft) than Ekeh-1 (17.8ft). This has been interpreted as due to the northwest bounding fault removing the upper part of the reservoir rather than stratigraphic thinning. Logs indicate that the hydrocarbon type is oil and this was confirmed by the recovery of an MDT sample of oil from the reservoir in Ekeh-2H. The OWC on Iku-3 depth map (Figure 4-3) shows the field extends outside of the licence area to the northwest to beyond the edge of the seismic data provided. However, the column is only 40ft thick in the saddle between the southeast crest and the northwest culmination so recognising the uncertainty in depth conversion, this saddle was used to define the minimum P90 case. The base case GRV encompassed the area above the OWC to the edge of the seismic map.

The RMS amplitude map for Iku-3 (Figure 4-4) shows two positive areas, in the southeast adjacent to the wells and in the culmination to the northwest. This suggests that oil is present outside the minimum defined area although the low amplitude between the two areas shows they may not be connected.

Figure 4-3: Iku-3 depth map



Figure 4-4: Iku-3 RMS amplitude

Shallow OWC

Deep OWC

GRV P90 Total/License

GRV Mean Total/License N/G PHIE Sw

FVF m3*106 m3*106 fraction fraction fraction

-4193.8 -4193.8 18.78

17.81

31.10

19.32 0.694 0.323 0.331 1.173

Table 4-3: Iku-3 GRV range and likeliest reservoir parameters

Area STOIIP MMstb

Mean P90 P50 P10

Structure 22.1 12.7 20.8 33.3

Licence 13.7 12.1 13.8 12.6

Table 4-4: Iku-3 STOIIP volumes



4.3. Iku-5

The Iku-5 reservoir is present in both wells where logs indicate that it contains gas. No hydrocarbon contacts have been seen in this reservoir and gas volumes have been calculated on the range from lowest seen gas in Ekeh-2H to the spill point of the structure (Figure 4-5). This upside gas case gives a 73ft of untested hydrocarbon column which could contain an oil leg down dip from the well.


The Iku-5 amplitude map shows poorly defined amplitude anomalies which is probably due to the thinness of the reservoir (30ft) as it is below seismic resolution. The very limited seismic amplitude anomaly present shows a degree of correlation with the minimum case area used in the GIIP forecast (Figure 4-6).




Shallow GWC

Deep GWC


GRV P10 Total/License N/G PHIE Sw

GEF m3*106 m3*106 fraction fraction fraction

-4447.2 -4520.0 5.30

5.29

16.10

10.17 0.386 0.287 0.337 125.0


Area GIIP bcf

Mean P90 P50 P10

Structure 3.3 1.7 3.0 5.3

Licence 2.6 1.7 2.4 3.3

Table 4-6: Iku-5 GIIP volumes



4.4. Iku-6

Ekeh-1 found the Iku-6 reservoir to be gas charged. However, logs from the down dip well Ekeh-2H show both a GOC and an OWC. The 4615ft contour of the OWC shows the field extends beyond the edge of the depth map to the northwest. However, the column is only 35ft thick in a saddle between the southeast crest and the northwest culmination so, recognising the uncertainty in depth conversion, this saddle was used to define the minimum P90 case (Figure 4-7). The base case GRV encompassed the area above the OWC to the edge of the map.


Plotting the Iku-6 GOC contour on the seismic amplitude map (Figure 4-8), shows a strong correlation of bright amplitudes with the gas charged reservoir in the southeast culmination. As the wet sand / shale interfaces have lower seismic impedance contrast than gas sand / shale interfaces, this amplitude response is expected and should produce a class III AVO anomaly. Interestingly, there is a second bright amplitude anomaly to the north of Ekeh. It covers a small (0.2 km2) low relief (20ft) closure and is expected to contain gas. The plotted OWC shows the relationship between amplitude and the oil leg is less clear.




Hydrocarbon Type HWC


GRV Mean Total/License N/G PHIE Sw GEF

FVF m3*106 m3*106 fraction fraction fraction

Gas -4570.0

21.45 21.02

22.89 21.89 0.718 0.258 0.279

125.0

Oil -4615.0

11.97 10.27

23.52 12.28 1.173


Area GIIP bcf

Mean P90 P50 P10

Structure 13.6 11.2 13.4 16.1

Licence 12.9 11.0 12.9 15.0

Table 4-8: Iku-6 GIIP volumes

Area STOIIP MMstb

Mean P90 P50 P10

Structure 16.2 8.4 15.0 25.9

Licence 8.5 7.2 8.6 7.4

Table 4-9: Iku-6 STOIIP volumes



4.5. Ewinti-2.0

The Ewinti-2.0 is the thinnest (29ft) and poorest of the hydrocarbon bearing reservoirs. Logs indicate that the reservoir is charged with gas in Ekeh-1 and oil in Ekeh-2H thereby indicating a GOC between -4905ft and -4950ft TVDSS. No OWC was seen in Ekeh-2H so there is significant uncertainty on the limits of the oil accumulation. In-place gas and oil volumes were calculated for this reservoir with a triangular distribution of GRV. For the base case (Figure 4-9) the GOC from the Ewinti-2.1 reservoir was used with an oil spill point at -5040ft TVDSS across the northern bounding fault.

Figure 4-9: Ewinti-2.0 depth map

The seismic amplitude map (Figure 4-10) shows poor correlation between the structure and amplitude. This is due to the Ewinti-2.0 reservoir being below seismic resolution although the brightest amplitudes are in the gas charged area in the southeast.



Figure 4-10: Ewinti-2.0 RMS amplitude

HC Type

Shallow HWC

Deep HWC

GRV min Total/ Licence

GRV base Total/ Licence

GRV max Total/ Licence

N/G PHIE Sw GEF/Bo

m3*106 m3*106 m3*106

Gas -4905.2 -4950.5 4.86 4.86

6.71 6.68

7.13 7.06 0.790 0.249 0.192

125

Oil -4971.0 -5080.0 1.12 1.04

4.83 4.16

14.22 7.81 1.17

Table 4-10: Ewinti-2.0 GRV range and likeliest reservoir parameters

Area GIIP bcf


Table 4-11: Ewinti-2.0 GIIP volumes

Area STOIIP MMstb


Table 4-12: Ewinti-2.0 STOIIP volumes



4.6. Ewinti-2.1

The Ewinti-2.1 is the largest discovered reservoir at Ekeh. Only Ekeh-1 drilled the full section of the reservoir (92ft). It showed a GOC at -4942.1ft TVDSS and below which was charged with oil to the base of the sand. Ekeh-2H was drilled horizontally through the oil leg in this reservoir. As an OWC has not been penetrated in this reservoir, there is a fairly wide range of STOIIP with the minimum P90 case almost exclusively contained in the farm-out area while the maximum case extends to the edge of the map to the northwest (Figure 4-11).

Figure 4-11: Ewinti-2.1 depth map

The amplitude map shows a strong anomaly in the minimum case, southeast part of the field (Figure 4-12). There is no amplitude support for the upside case although there is less impedance contrast at oil sands/shale interfaces and wet sand/shale interfaces than when gas is present.



Figure 4-12: Ewinti-2.1 RMS amplitude

HC Type

Shallow HWC

Deep HWC

GRV P90 Total/Lic.

GRV P10 Total/Lic. N/G PHIE Sw GEF/

Bo m3*106 m3*106 fraction fraction fraction

Gas -4942.1 -4942.1 9.53 (P50)

4.86

10.02

9.53 0.791 0.279 0.175

125.0

Oil -5020.0 -5120.0 18.45

18.12

60.84

45.82 1.173

Table 4-13: Ewinti-2.1 GRV range and likeliest reservoir parameters

Area GIIP bcf


Table 4-14: Ewinti-2.1 GIIP volumes

Area STOIIP MMstb


Table 4-15: Ewinti-2.1 STOIIP volumes



4.7. Ekeh Field Probabilistic STOIIP Summary

Reservoir Mean P90 P50 P10 Iku 3 22.1 12.6 20.8 33.4

Iku 6 16.2 8.3 15.0 25.9

Ewinti 2.0 5.8 2.7 5.4 9.4

Ewinti 2.1 37.0 17.7 33.0 60.8

Total 81.1 54.8 78.0 110.7

Table 4-16 Ekeh Field Probabilistic STOIIP Summary

A probabilistic addition of the STOIIP from the main oil bearing reservoirs in Ekeh indicate a P90 to P10 uncertainty range between 55 and 110 million barrels of oil. One of the key uncertainties is the extension of the reservoir from the Ekeh “main” segment in the southeast to the Ekeh NW segment in the northwest. For the Iku-3 and -6 reservoirs, the extension to the northwest seems highly likely as the structure lies above the OWC demonstrated in Ekeh-2H. For oil not to be present, there would need to be a fault or stratigraphic barrier separating the NW segment from the Ekeh “main” area in the SE.

For the Ewinti-2.1 formation, there is no known OWC so the extension is less certain, and our P50 estimate for the likely OWC lies close to the spill point in Ekeh main, so the NW extension could be water bearing.



5. Ekeh Field Volumetrics & Uncertainty In order to create an appraisal and development plan which took into account the current state of uncertainty of the Ekeh reservoirs, it was useful to develop a decision tree for appraisal, and define outcomes for recoverable volumes for discrete development options. To facilitate this, STOIIP volumes and probabilities were assigned to various reservoir segments

5.1. Deterministic STOIIP Segments

5.1.1. Iku-3

Figure 5-1 Iku-3 Reservoir Segments

Iku-3 STOIIP MMstb Comment

SE NW

Minimum 15.1 0.0 Oil restricted to Ekeh main down to OWC. No oil in NW. Requires an appraisal well to test NW, and a horizontal development well in Ekeh main.

Base case 15.1 9.9 Oil extends to NW, with a common OWC. Appraisal well completed with dual completion in NW. 1 horizontal well in Ekeh main

Maximum 16.1 14.1 OWC same as base case but with better reservoir quality to give upside volumes. An extra production well dedicated to Iku-3 in the NW may be justified.

Table 5-1 Iku-3 Deterministic STOIIP Segments



5.1.2. Iku-6

Figure 5-2 Iku-6 Reservoir Segments

Iku-6 STOIIP MMstb Comment

SE NW

Minimum 8.6 0.0 Oil restricted to Ekeh main down to OWC. No oil in NW. Requires an appraisal well to test NW, and a horizontal development well in Ekeh main.

Base case 8.6 8.3 Oil extends to NW, with a common OWC. Appraisal well completed with dual completion in NW. 1 horizontal well in Ekeh main

Maximum 11.0 14.2

OWC same as base case but with better reservoir quality to give upside volumes. An extra production well dedicated to Iku-3 in the NW may be justified.

Table 5-2 Iku-6 Deterministic STOIIP Segments

The situation in Iku-6 is similar to Iku-3: An appraisal well is needed to test for oil in the NW segment, and if present Iku-6 could be produced together with the Iku-3 with a dual completion. In Ekeh main, separate horizontal producers are required for Iku-6. In the upside case, with better reservoir parameters, but the same OWC as the base case, 2 wells may be required in the NW to accelerate production from Iku-3 and -6 simultaneously.



5.1.3. Ewinti-2.1

Figure 5-3 Ewinti-2.1 Reservoir Segments

Ewinti-2.1 STOIIP MMstb Comment

SE NW

Minimum 18.0 0.0 Minimum case OWC, with oil restricted to Ekeh main area in SE. Requires 1 horizontal development well.

Base case 36.6 0.0 P50 OWC, but still restricted to SE area. May require 2nd horizontal development well in SE.

Maximum 50.3 9.2

Deeper OWC extends to NW. 2nd horizontal well in SE required, plus an additional completion in the NW.

Table 5-3 Ewinti-2.1 Deterministic STOIIP Segments

The base case expectation is for oil to be restricted to Ekeh main in the SE. This needs to be confirmed by the NW appraisal well. The OWC is currently unknown, and a pilot hole is required from the Iku-6 development well to test the OWC in the Ewinti-2.1 to determine whether a 2nd horizontal well is required for the Ewinti-2.1 in the SE area.

5.1.4. Ewinti-2.0

The volumes in the Ewinti-2.0 are very small and do not justify dedicated wells. However, late stage recompletions of Ewinti-2.1 wells could be considered when the Ewinti-2.1 is depleted.



Ewinti-2.0 STOIIP MMstb Comment

SE NW

Minimum 1.0 0.0 Possible late stage recompletion. Base case 4.1 0.0 Possible late stage recompletion. Maximum 8.1 4.0 Possible late stage recompletions.

Table 5-4 Ewinti-2.0 Deterministic STOIIP Segments

5.1.5. Deterministic STOIIP Volumes

The deterministic STOIIP calculations indicate a minimum STOIIP of 42.6 MMstb, and maximum of 127 MMstb. The mid case of 82.6 is similar to the mean probabilistic case of 81 MMstb. The benefit of using the deterministic cases is to enable a drilling programme to be planned.

Reservoir Segment min mid max

Iku 3 SE 15.1 15.1 16.1 Iku 3 NW 0.0 9.9 14.1 Iku 6 SE 8.6 8.6 11.0 Iku 6 NW 0.0 8.3 14.2 Ewinti 2.0 SE 1.0 4.1 8.1 Ewinti 2.0 NW 0.0 0.0 4.0 Ewinti 2.1 SE 18.0 36.6 50.3 Ewinti 2.1 NW 0.0 0.0 9.2 Total 42.6 82.6 127.0

Table 5-5 Summary of Ekeh deterministic STOIIP volumes

5.2. Appraisal Programme

Based on the reservoir uncertainties described above, the following drilling programme is proposed:

Drill appraisal well� (App-1) in the NW segment. Test presence of oil in Iku-3, Ekeh-6, Ewinti-2.1. It is unlikely that all three reservoirs will be well developed in the same location, but if they are, then a second development well will be needed for the NW, and a sequential completion schedule. The App-1 well may also gain possible knowledge of OWC in Ewinti-2.1 which will enable the optimal datum to be determined for the drilling of a horizontal producer in the SE (Dev-1).

Re-drill Ekeh-2H� (Dev 1) in Ewinti-2.1 main to get early revenue and well test to estimate connected volumes. There is a risk of placing the horizontal section too close to either the GOC or OWC. Depending on the results of App-1, optimisation may be possible. A pilot hole to test the OWC is not viable because in the area of the heel of the well there is no OWC. The water will be down dip to the northwest.

Drill Iku-3 horizontal well in main (Dev-2).

Drill Iku-6 horizontal well in main (Dev-3). Drill pilot hole to confirm Ewinti-2.1 OWC.



If the pilot hole from Dev-3 demonstrates a sufficiently deep OWC or moved OWC, drill a second Ewinti-2.1 horizontal well (Dev-4) in main SE area.

Optional second well (Dev-5) in NW if App-1 reveals a high case.

�Note: MDT should be run in either App-1 or Dev-1 to acquire PVT samples

Dependent upon reservoir performance it is possible and appraisal success, it is possible that an additional well might be needed in the NW area. Further exploration/appraisal could be undertaken to evaluate the deeper Ewinti formations, hence a 7th well could be needed. However, it the present time these possibilities are not regarded as part of the primary development, and would only be considered in a later phase of development, possibly re-using an existing well slot.

The appraisal programme is designed to enable key decision to be made about the size of the wellhead platform required (3-8 slots, based on 3-6 well primary development and 2 spare slots) and the processing capacities required on a refurbished Middleton Production Platform. It should be noted that an MDT should be run in App-1 to acquire pressure measurements and downhole samples for PVT analysis on the Ewinti 2.1 and Iku-6 reservoirs in the oil leg. Should either or both reservoirs not be HC bearing in App-1 well, then the MDT should be run in Dev-1 (though this would be more costly and risky due to planned hole orientation). PVT for the Ewinti 2.1 and Iku-6 remains an uncertainty and it should be resolved prior to planning off-take policy for the reservoirs in the production phase.

5.3. Decision Tree

Following the logic of the appraisal programme, a decision tree (Figure 5-4) has been constructed showing the various STOIIP outcomes from appraisal. The key event is the drilling of the App-1 NW appraisal well which could confirm oil in the Iku-3 and Iku-6 and possibly also in the Ewinti-2.1. If App-1 is dry, the Ekeh field will be limited to the main area in the SE, and could be developed with 3 or 4 wells, depending on the OWC in Ewinti-2.1 which will be confirmed by the Dev-3 pilot hole.

If oil is found in App-1, it could be in the Iku or Ewinti, or both formations, and various outcomes have been identified in the decision tree. The outcome considered most likely is to find oil in the Iku-3 and Iku-6, with the same OWC as in Ekeh-2H, but with no oil in the Ewinti-2.1 in the NW area, and the P50 OWC in the SE area confirmed by the Dev-3 pilot hole. This forms the mid case and is identified as case 4 in the decision tree which results in a 5 well development.

A 4-well development could arise from either drilling 4 wells in the SE (if the Ewinti-2.1 OWC is deep enough to justify 2 wells), or from 3 wells in the SE (if the Ewinti-2.1 OWC is shallow) plus one well in the NW.

A 6 well development could arise if high side outcomes are found in the NW, and a second well is needed to accelerate production. If oil is found in all three reservoirs in the NW then 2 dual completion wells may be necessary.

In the extreme high cases, an additional (7th) well might be required to efficiently drain the Ewinti-2.1, but this case is only likely to be considered in a later phase of development.

There are additional further possibilities for appraisal, such as the Lower Ewinti or possible satellites in adjacent fault blocks, but these are currently thought to be of higher risk and lower reward than the main field, and are not included in the primary



development stage. This possible future upside is not included in the decision trees for the current development project.

Cases in the decision tree are numbered 1 to 14, starting from the bottom, with cases 1, 4, 5 and 12 (highlighted in red) selected for detailed development planning and reservoir modelling.

Figure 5-4 Decision Tree showing STOIIP outcomes in 14 deterministic cases

After assigning probabilities to the various branches on the decision tree, a rough pseudo-cumulative probability curve was drawn (Figure 5-5) which shows that case 4, with STOIIP of 82.6 MMstb represents approximately the P50 point on the distribution, which is comparable to the P50 derived from Monte Carlo simulation. Similarly, the P90 and P10 at around 50 and 100 MMstb are comparable with the Monte Carlo results.

Recoverable volumes were estimated (see section 7) for the 4 selected cases (cases 1, 5, 4 & 12) in the decision tree to describe development scenarios for 3, 4, 5 or 6 well developments.

The recoverable volumes from the full field development range from 12.3 to 34.0 MMstb. The mid case (case 4) yields 25.1 MMstb.

When compared to the probabilistic estimates for reserves (Figure 5-6), it can be seen that the minimum deterministic case (Case 1) is less than the P90 estimate from probabilistic estimation. The Base case (Case 4) is very similar to the P50 estimate, and the High case (Case 12) is similar to the P10 case from probabilistic estimation.

Also plotted on Figure 5-6 are the reserves estimates made independently by Movido, which have a similar P90-P10 range. This confirms Movido’s estimates, even though Movido only made probabilistic estimates, and did not specify detailed deterministic



development plans based on specific well numbers and locations to develop these resources.

Figure 5-5 STOIIP Pseudo Cumulative Probability Curve from 14 Deterministic Cases

Figure 5-6 Deterministic Cases plotted on the Probabilistic Distribution



5.4. Minimum (Case 1) – 3 well development

If App-1 fails to find oil in the northwest, the development will focus on the Ekeh main field area in the south east. Provided that the long term testing from the early production scheme supported a full field development, the minimum case would be a 3 well development with one well dedicated to each of the Ewinti-2.1 (Dev-1) Iku-3 (Dev-2) and Iku-6 (Dev-3). This would develop a STOIIP of 42.7 MMstb, yielding recoverable volumes of 12.3 MMstb. The Ewinti-2.0 may be developed later by a secondary completion on Dev-1, but modelling suggests that recoverable volumes will be limited unless >P90 STOIIP is present in the SE.

This scenario incorporates a number of risks. First, there is a threat of early gas breakthrough in Dev-1 which could reduce oil recovery, and may also cause gas disposal problems or limit production through gas handling constraints. Second, there is a risk that after the initial production in the early production stage, the remaining recoverable volumes in the field are insufficient to justify installation of a wellhead platform and refurbishment of Middleton. In this worst case, it may be necessary to abandon the development of Ekeh, or possibly continue limited production via the early production scheme, if gas flaring permits allow.

Figure 5-7 Minimum Case 3 well Development Scenario Schematic



5.5. Low (Case 5) – 4 well development

If App-1 finds oil in the northwest in the Iku-3 and Iku-6 with the expected OWC and P50 volumes, but no oil in the Ewinti-2.1, the NW area can be developed with App-1 completed with a dual completion. Dev-1 is drilled in the Ewinti-2.1, and if the early production system demonstrates sufficient production potential, a full field development could be justified. After platform installation, Dev-2 and Dev-3 would target the Iku-3 and Iku-6 in the SE area.

If the Dev-3 pilot hole in the SE area finds an OWC in the Ewinti-2.1 somewhere between the P90 and P50 level, and production data from Dev-1 indicate downside potential, it may be decided not to drill a second production well in the Ewinti-2.1. In this case, full field development would be limited to 4 wells (App-1, Dev-1, Dev-2 and Dev-3) In total there are 4 production wells and 5 drainage points (3 horizontal wells, 1 deviated dual completion).

This scenario would develop a STOIIP of 64.3 MMstb, yielding recoverable volumes of 18.95 MMstb. The Ewinti-2.1 reservoir would be relatively inefficiently drained by only one well, but due to the relatively thin oil column over most of its area, a second well would not be justified.

The Ewinti-2.0 may be developed later by a secondary completion on Dev-1, but modelling suggests that recoverable volumes will be limited unless >P90 STOIIP is present in the SE.

Figure 5-8 Low Case 4 well Development Scenario Schematic



5.6. Base (Case 4) – 5 well development

In the mid case scenario, App-1 finds oil in the Iku-3 and Iku-6, but not in the Ewinti-2.1. App-1 is completed as a dual completion in the NW. Dev-1 is drilled in the Ewinti-2.1, and the early production scheme demonstrates sufficient production potential to justify a full field development. After platform installation, Dev-2 and Dev-3 target the Iku-3 and Iku-6 in the SE area. The pilot hole in Dev-3 demonstrates that the OWC in the Ewinti-2.1 is at the P50 level or better, and a second well in the Ewinti-2.1 (Dev-4) is drilled.

This scenario assumes a P50 STOIIP in the Ewinto-2.0 and Dev-1 is recompleted to this zone after depleting the Ewinti 2.1 reservoir.

In total there are 5 production wells and 7 drainage points (4 horizontal wells, 1 deviated dual completion, 1 recompletion). This scenario develops a STOIIP of 82.6 MMstb, yielding recoverable volumes of 25.13 MMstb.

Figure 5-9 Base Case 5 well Development Scenario Schematic



5.7. High (Case 12) – 6 well development

In the high case scenario, App-1 finds oil in the Iku-3 and Iku-6 in the NW, and also oil in the Ewinti-2.1. App-1 could be completed as a dual completion in the NW, but can only develop 2 of the 3 reservoirs. Depending on the well results, a decision would have to be taken on which combination of completions would be optimal. The Iku-3 and -6 have relatively low production potential from a vertical completion, and really need horizontal wells for optimal development. Modelling of various options indicates that if there is significant oil in the Ewinti-2.1, the optimal development would be to produce the Ewinti-2.1 with a single completion, then later sidetrack to develop the Iku-3 with a horizontal well, and drill a separate well (Dev-5) as a horizontal in the Iku-6. This configuration has been selected to develop the NW area.

The SE area, as in the previous case is developed with Dev-1 and Dev-4 in the Ewinti-2.1, with options for late completion in the Ewinti-2.0. Dev-2 and Dev-3 target the Iku-3 and Iku-6 in the SE area. In total there are 6 production wells, of which 5 are dedicated horizontal wells, whilst App-1 is initially a deviated well, subsequently sidetracked as a horizontal after depleting the Ewinti 2.1 reservoir.

There is potential to consider multi-lateral completions to develop more than one reservoir concurrently with horizontal wells, but these have not been proposed at this stage due to drilling complexity. In total there are 7 production wells and 8 drainage points (4 horizontal wells, 1 deviated well, one recompletion and one sidetrack). This scenario develops a STOIIP of 109.3 MMstb, yielding recoverable volumes of 33.9 MMstb. The Ewinti-2.0 is not developed initially, but produced by later recompletions.

With the large STOIIP volume in the Ewinti-2.1, it is possible that a third well might be drilled into the Ewinti-2.1 in the SE area in a later phase of development. This possible 7th well is noted a possibility, but not considered to be part of the primary field development.

Figure 5-10 High Case 6 well Development Scenario Schematic



6. Reservoir Engineering Limited information exists about the reservoir extent, fluid contacts and properties, in place volumes and well productivity. Hence further appraisal is required before a full field development plan can be defined. Reserves potential from a range of development scenarios has been assessed to guide the appraisal programme and early development planning.

6.1. Well Tests Two well test have been performed on the discovery to date via discovery well Ekeh-1 and subsequent appraisal well Ekeh-2H. Ekeh-1 tested the Ewinti-2.1 reservoir in 1987 in a vertical well completion. Ekeh-2H tested both the Iku-6 reservoir and the Ewinti-2.1 reservoir independently in 2008 through a dual string completion. The Ewinti-2.1 was completed horizontally and tested through the Long String while the overlying Uku-6 was a perforated completion tested through the Short String. The zones were isolated during the test via packers. The available well test information includes:

For Ekeh-1 (Ewinti-2.1 reservoir)

Surface production test and well head pressure measurements from a 17 hr DST in Jan 1987.

For Ekeh-2H-H (Iku 6 and Ewinti-2.1 and reservoirs):

Surface production test and well head pressure measurements for the Iku-6 and Ewinti-2.1 reservoirs over the test period from 24th Nov 2008 to 22nd Dec 2008

Five downhole gradient surveys taken in the long string (Ewinti-2.1) on the 5th Dec, 10th Dec, 11th Dec 2008, 15th Dec and .

o 5th Dec: Shut-in (SI) gradient survey. The survey was taken on immediate SI of the tubing and is therefore not valid

o 10th Dec: SI gradient survey. The survey was taken after ±3 hrs of SI and SIWHP has not stabilised. After completion of the survey SIWHP rose from 220 psi to 340 psi.

o 11th Dec: Flowing gradient survey: The survey was taken immediately on opening of the tubing after 48 hrs SI. The survey does not therefore represent stabilised flow conditions in the tubing.

o 15th Dec: SI gradient survey reported. Conducted after 2.25 hrs SI. Data not available to AGR for analysis.

o 17th Dec: Gauges reportedly run and hung off for downhole pressure survey during reported flow test of Ewinti-2.1 (17th – 22nd Dec). Data not available to AGR for analysis (not known if gauges successfully recorded any data)

Unfortunately, no bottom hole drawdown or build-up or pressure data was available from the testing of Ekeh-1 or Ekeh-2H, therefore no independent pressure transient analysis interpretation is possible to define reservoir parameters.

6.1.1. Ekeh-1

The Ekeh-1 well intersected the top of the Ewinti-2.1 sand at 5,125 ft measured depth (4,929 ft TVD) and the base at 5,237 ft measured depth (5,022 ft TVD) with a gross thickness of 93 ft. In January 1987 the well tested at rates of up to 2,100 BOPD of 34.8 API crude at the end of the 17 hr DST. Average GOR was 360 SCF/STB with gas S.G of



0.75. The well was tested at different chokes and the recorded oil rates gradually increased as the wellbore cleaned up. Figure 6-1 shows oil rates tested in Ekeh-1.

Figure 6-1 - Ekeh-1. DST test results

6.1.2. Ekeh-2H

A horizontal well Ekeh-2H was drilled in June 2005. The well has a dual completion with a short string completed in Iku-6 reservoir and a long string completed in Ewinti-2.1 reservoir. The well was tested in December 2008 and the maximum recorded rate at 32/64” choke for the Iku-6 (short string) was 250 BOPD over more than a week’s testing. The Ewinti 2.1 reservoir (long string) produced during 44 hr flowing test an average of 1,050 BOPD of 28.5 API crude at 210 psig FWHP on a 32/64” choke. Average GOR was 250 SCF/STB with gas S.G of 0.7. It should be noted that the recorded fluid properties for the reservoir are substantially different from those reported from the Ekeh-1 test in Ewinti 2.1 reservoir.

The well completion operations were not conducted satisfactorily and post well evaluations conducted by Movido suggest the Ewinti 2.1 reservoir was damaged and formation collapse is known to have occured. Both zones produced sand during testing (downhole and to surface).

6.2. Production History There is no production history from Ekeh.

6.3. Recovery Factors

6.3.1. Oil Recovery Factors

The range of oil recovery factors has been considered by two independent means. Firstly, for input to Monte Carlo simulation, an examination of available public domain information regarding neighbouring fields offshore West Africa as well as general knowledge on achieved oil recovery in the similar reservoirs worldwide. Secondly, recovery factors were calculated per reservoir using integrated production system model(s) which incorporated well productivity (inflow/outflow), dynamic reservoir



behaviour over time and surface production system constraints (Prosper/MBAL/GAP software by Petex).

There are four oil bearing reservoirs identified in the Ekeh field: Iku-3, Iku-6, Ewinti-2.0 and Ewinti-2.1. Three of these reservoirs have gas caps (Iku-6, Ewinti-2.0 and Ewinti-2.1) that imply a high probability of a gas cap reservoir drive mechanism. Based on the log analysis a gas cap has not been seen in the fourth reservoir Iku-3 thus it is expected to be a solution gas drive. Aquifer support, if present in the Iku-3 reservoir may positively affect oil displacement and help to achieve higher oil recovery compared to the depletion under solution gas drive. The range in oil recovery factors for gas cap drive reservoirs are expected to be similar to the range for the solution drive reservoirs.

For Monte Carlo simulation, Oil reservoirs were assigned a range of recovery factors varying from 0.20 to 0.40. The ranges of oil recovery factors applied in the probabilistic Monte Carlo simulation are shown in Table 6-1. A Normal probability distribution was set as an assumption in the Monte Carlo simulation of the oil recovery factors.

Reservoir Low RF Mid RF High RF

Iku-3 0.20 0.3 0.40

Iku-6 0.20 0.3 0.40

Ewinti-2.0 0.20 0.3 0.40

Ewinti-2.1 0.20 0.3 0.40

Table 6-1 Range of oil recovery factors

Reservoir Mean P90 P50 P10

Total STOIIP 81.1 54.8 77.9 110.8

Recoverable 26.3 14.8 24.4 40.0

Table 6-2 - Probabilistic STOIIP and Recoverable Oil (MMstb)

6.3.2. Gas Recovery Factors

Gas recovery factors depend on the type of gas under consideration. Free gas is present in reservoirs Uro-9 and Iku-5; Gas caps are present above oil in reservoirs Iku-6, Ewinti-2.0 and Ewinti-2.1; and no gas cap has been observed in Iku-3. It is estimated that free gas recovery factors will be somewhat higher than recovery factors of the gas cap gas.

To account for the uncertainty with regard to the gas recovery, the following ranges were used as input to Monte Carlo simulation.

Low RF Mid RF High RF

Gas cap recovery factors 0.45 0.55 0.65

Free gas recovery factors 0.50 0.70 0.85

Table 6-3 - Range of gas recovery factors

Reservoir Mean P90 P50 P10

Total GIIP 37.4 31.8 36.8 43.9 Recoverable 22.2 18.3 21.7 26.6

Table 6-4 - Probabilistic GIIP and Recoverable Gas (Bscf)



6.4. Oil and Gas Properties

Three sources of available data regarding oil properties for the Ekeh reservoirs have been utilised, namely:

1. Field measurements obtained from surface sampling DST of the Ewinti-2.1 reservoir in the Eheh 1 well; API / gas SG / GOR1.

2. Laboratory PVT analysis for downhole MDT sample acquired at -4,157 ft TVDss in 2005 in Iku-3. Laboratory report PVT-57/2006.

3. Field measurements obtained from surface sampling of the long-string during testing of the Ewinti 2.1 reservoir in the Eheh-2H well; API / gas SG / GOR.

1Results from Eheh-1 test were carried forward for modelling and forecasting. Should heavier and more viscous crude be contained within the reservoir (as suggested by Ekeh-2H test), then forecast well rates will be optimistic for the same sandface drawdown.

A summary of the reported PVT for the Iku-3 reservoir is shown in Table 6-5 (obtained from PVT report PVT-57/2006 by LASER Laboratories) while surface measured fluid property data for the Ewinti 2.1 and Iku-6 reservoir is shown in Table 6-5.

Reservoir pressure in the Ewinti 2.1 and Iku-3 was estimated by extrapolating from Iku-3 MDT pressure using reported fluid gravity and corresponding pressure gradients (Iku-3 is normally pressured). It should be noted that there is a substantial difference in the fluid PVT reported for the Ewinti 2.1 reservoir from the Ekeh-1 and Ekeh-2H well tests; both reported for surface acquired field measured samples.

The Ekeh-1 well reported 34.8 API crude with a GOR of 440 SCF/STB and gas S.G of 0.75, while Ekeh-2H reported 28.5 API crude at with average GOR of 250 SCF/STB and S.G of 0.7. The sample from Ekeh-1 has been taken as correlations give a better match for initial pressure equal to bubble point at anticipated reservoir pressure. Additional PVT studies will need to be performed as new wells are drilled in the appraisal phase of the Ekeh development project to verify PVT properties in Table 6-5 and reservoir pressures in Table 6-7. If Ewinti 2.1 crude is more viscous than assumed (i.e. as suggested Ekeh-2H sample), then achievable well rates would be negatively affected with a PI reduction of some 50% or more.

Reservoir Pressure (Iku-3) psia 1,844

Saturation Pressure (Iku-3) psia 1,712

Reservoir Temperature (Iku-3) 0F 146.5

Oil gravity (stock tank) 0API 25.2

Oil viscosity at reservoir conditions cP 3.259

Oil FVF rb/stb 1.173

Oil compressibility at 1844 psia 1/psia 8.71E-06

Gas gravity fraction 0.653

Separator GOR scf/stb 245

Gas FVF rcf/scf 0.008

Table 6-5 - Lab PVT analysis results Iku-3



Reservoir deg.API SG GOR (scf/stb)

Ewinti 2.1� ±35.6 ±0.75 ±440

Table 6-6 – Surface sample measured PVT Ewinti 2.1 and Iku-6 1Sample from Ekeh-1 well. Ekeh-2H sample from same reservoir shows 28.5 API crude at with average GOR of 250 SCF/STB and S.G of 0.7

Estimated Reservoir

Pressure, psia

IKU-3 Oil 1,844*

IKU-6 Oil 1,888

EWINTI-2.0 Oil 2,027

EWINTI-2.1 Oil 2,131

* Note: MDT measurement from Iku-3

Table 6-7 - Reservoir pressure estimation in Ekeh field.

Oil reservoirs Iku-6, Ewinti-2.0 and Ewinti-2.1 have gas caps. Saturation pressures in these reservoirs are equal to the estimated reservoir pressures at initial conditions. The presence of gas caps in these oil reservoirs implies that aquifer may not be strong enough to provide sufficient pressure support, and the reservoir pressure may drop at a high rate. In fact such reservoir behaviour was observed in the neighbouring Middleton Field where in the Ewinti 5.1 formation the reservoir pressure declined very rapidly.

Reservoir permeability was estimated based on petrophysical analysis reported in Section 4.0. Horizontal permeability estimation was carried out for each reservoir layer. The calculation was based on the Timur and Biggs porosity models. Both these models have historically been used in calculating permeability from NMR data, where both PHIE and irreducible water saturation are measured by the tool. Values of irreducible water saturation and clay volume were assumed to benchmark against a range of such properties in analogous clastic reservoirs with high and low porosity. Permeability estimation for Ekeh oil reservoirs are shown in Table 6-8.

Horizontal permeability, mD

Low Mid High

IKU-3 Oil 372 1,205 4,503

IKU-6 Oil 321 956 3,138

EWINTI-2.0 Oil 265 729 2,203

EWINTI-2.1 Oil 226 583 1,638

Table 6-8 - Horizontal permeability estimation



6.5. Well Productivity

Ekeh could be developed by either vertical/deviated or horizontal wells, with single or dual completions. To determine the optimal well type, nodal analysis models were constructed using Prosper software.

For each of the reservoirs a model was built to evaluate the performance of a 30 degree deviated well from and a horizontal well. For the deviated producer, well inflow was calculated using Jones reservoir model, Karakas and Tariq mechanical/geometric skin model and Cinco - Martin deviation/partial penetration skin model. Ewinti 2.1 and Iku-6 were modelled with a 20 vertical ft completion while Iku-6 was modelled with a 10 vertical ft completion, both in 8.5” cased hole.

For the horizontal well the three main reservoirs were modelled with a 500m drainage section in 8.5” hole. Well inflow was calculated using PETEX horizontal well model while damage skin was entered as a fixed value. Note that a single deviated and horizontal well geometry was modelled all reservoirs (with necessary adjustments to depth).

Table 6-9 shows the resultant Productivity Index calculated for the wells. The base case permeability values adopted for the evaluation are highlighted in bold.

Table 6-9 – Calculated well PI for main development targets

Deviated well Horizontal well

Ewinti 2.1 k = 16381 mD k = 583 mD k = 226 mD k = 1638 mD k = 583 mD k = 226 mD

Actual PI (stb/d/psi) 17.8 10.7 5.7 294.5 104.3 40.5

Iku 3 k = 4503 mD k = 1205 mD k = 372 mD k = 4503 mD k = 1205 mD k = 372 mD

Actual PI (stb/d/psi) 8.4 5.6 2.8 254.7 68.9 21.4

Iku 6 k = 3138 mD k = 956 mD k = 321 mD k = 3138 mD k = 956 mD k = 321 mD

Actual PI (stb/d/psi) 5.5 3.6 1.9 195.5 59.5 20.0 Note: Tabulated permeability values in Bold represent the current Base Case assumptions and these values were taken forward to forecasting. Kv/kh was taken as 0.7. 1Should the Ewinti 2.1 crude have PVT properties as suggested by the Ekeh-2H well test results, then the PI would by some 50%. Fluid properties is therefore a key uncertainty that requires resolution at the earliest opportunity.

Well performance was evaluated for a range of changing flowing conditions; for example with varying reservoir pressure, flowing wellhead pressure, increasing water cut and GOR etc. Inflow performance relationships and lift curves generated within Prosper were carried forward into GAP integrated production system analysis software and, in combination with MBAL material balance software, were used to generate asset production profiles for varying scenarios. Table 6-10 and Table 6-11 show the initial flowing rates achievable for the deviated and horizontal ‘type’ well per reservoir at initial flowing conditions.

The well test results showed that the target sands are relatively unconsolidated and sand control completions will be required from first production. Accordingly, the deviated wells were modelled assuming cased hole gravel packs inside 8.5” casing. Given the relatively short completion intervals open hole gravel packs were not considered. Horizontal wells were modelled with pre-packed screens. No core has been acquired for any of the reservoir and full bore core or core plugs should be acquired for analysis to allow for gravel pack and sand screen selection. This should be included in the data acquisition of the first appraisal/development well.

The results of the nodal analysis strongly supported the use of horizontal production wells rather than vertical or deviated wells due to the relatively thin oil columns, and presence of gas caps which threaten gas coning at high drawdown. Horizontal wells, with higher productivity indices could generate high well productivity at low pressure drawdown, and yielded higher total recovery.



Table 6-10 – Initial natural flowing rates vs. FWHP, deviated well, initial res conditions

FWHP Drawdown FWHP Drawdown FWHP Drawdown

(psig) (psig) bbl/d (psig) (psig) bbl/d (psig) (psig) bbl/d

100 85 6,455 100 92 3,023 not applicable

200 81 6,012 200 70 2,361

300 66 5,444 300 48 1,622

400 56 4,722 380 24 803

500 44 3,810 cannot flow

600 29 2,630

650 19 1,720

100 55 4,535 100 64 2,124 100 80 1,868

200 53 4,248 200 49 1,647 200 66 1,507

300 45 3,855 300 34 1,134 300 49 1,100

400 37 3,377 400 15 483 400 26 553

500 32 2,791 cannot flow cannot flow

600 23 2,024

650 16 1,437

not applicable 100 46 1,541 100 309 1,495

200 36 1,175 200 53 1,218

300 24 787 300 40 898

400 10 313 400 23 484

cannot flow cannot flow

Ewinti 2.1 Iku‐3 Iku‐6

4.5 in

3.5 in

2.875 in

Table 6-11 – Initial natural flowing rates vs. FWHP, horizontal well, initial res conditions

FWHP Drawdown FWHP Drawdown FWHP Drawdown

(psig) (psig) bbl/d (psig) (psig) bbl/d (psig) (psig) bbl/d

100 45 16,403 100 121 10,604 100 204 11,562

200 42 15,549 200 101 8,857 200 148 10,211

300 39 14,397 300 77 6,775 300 120 8,282

400 35 12,908 400 48 4,218 400 84 5,828

500 30 11,050 450 26 2,273 483 29 1,910

600 24 8,778 cannot flow cannot flow

720 6 2,414

100 19 7,127 100 53 4,629 100 77 5,301

200 18 6,732 200 43 3,789 200 67 4,628

300 17 6,185 300 32 2,810 300 55 3,737

400 15 5,463 400 17 1,507 400 40 2,605

500 13 4,667 cannot flow 480 15 871

600 10 3,596 cannot flow

690 6 2,236

Ewinti 2.1 Iku‐3 Iku‐6

4.5 in

3.5 in



The minimum FWHPs achievable will be dictated by surface facility constraints. During any pre-production phase to an onsite Early production scheme (EPS), minimum achievable FWHPs will likely be lower than those required for export to the Middleton Production Platform (for separation and onward evacuation to the export pipeline). Provisionally, a minimum separator inlet pressure of 100 psi is assumed at the Middleton Production Platform. At peak field rates this would friction drop along the Ekeh to Middleton Production Platform multiphase pipeline is some 250 psi at peak field rate assuming a nominal bore 10“ pipeline. This friction drop can rise rapidly in multiphase flow with decreasing reservoir pressure and increasing produced gas. Free gas production must therefore be closely controlled to avoid excessive friction loss. Therefore minimum effective FWHP for Ekeh will be some 300 – 400 psig assuming a minimum 100 psi separator inlet pressure. Initial production to an Early production scheme will be on Natural flow. Gas lift will be required in the Ekeh field shortly after the Middleton Production Platform comes online. To maximise off-take rates it is anticipated that gas lift will be required within ~one year of facility start up; therefore it may be preferable to install and commission gas lift with the initial facility upgrade.

Gas lift mandrels will be installed in the initial completions to allow the wells to be unloaded and kicked off following shut–ins. The Iku-3 reservoir will certainly require continuous gas lift after a short production period. Dependent upon the degree of free gas produced from the Ewinti-2.1 and Iku-6 reservoirs, these wells may also require continuous gas lift.

When the field is in production, separated gas can be used for gas lift, but after periods of total shutdown, a source of lift gas will be needed to restart production. It is planned to inject excess gas into one of the Middleton reservoirs (probably the Ekiti-3), and store it for later use for gas lift, and ultimately for export. Previous work proposed using the Middleton-2 well; though it should be noted that this study has not investigated any aspect of gas disposal at Middleton.

6.6. Material Balance Modelling

A series of material balance models was created representing each of the 4 selected development scenarios outlined in Section 5.4 to 5.7, these being referred to as Case 1, Case 5, Case 4 and Case 12. The material balance models were built using the MBal software package. Each of the 3 main reservoirs of the Ekeh field was split in to two segments: South East (SE) and North West (NW), according to the deterministic STOIIP volumetrics described in Section 5 and Table 5-5.

Two-tank material balance models were then constructed per reservoir unit (Iku-3, Iku-6, Ewinti-2.1). Within each reservoir unit, the SE and NW tanks were connected to allow transmissibility within the mode. Table 6-12 shows the reservoir and PVT parameters adopted within MBAL while Table 6-13 shows the STOIIP values per scenario. PVT tables were generated for Ewinti 2.1 and Iku-6 based on the fluid property and pressure data shown in Table 6-5, Table 6-6 and Table 6-7 using the correlations of Glaso (Pb, Rs, Bo) and Beggs et al (µ).



Parameter Iku-3 Iku-6 Ewi-2.1

Temperature, oC 146.51 1532 160.22

Initial pressure, psia 18441 18892 21312

API 251 291 35.81

Viscosity at reservoir conditions, cP 3.2591 1.1422 0.8242

GOR, scf/stb 2451 3002 4421

Gas SG 0.651 0.731 0.731

Porosity 0.32 0.258 0.28

Connate water saturation 0.13 0.13 0.13

Gas Cap No Yes Yes

Hurst-van Everdingen Water influx Yes Yes Yes

Residual oil saturation 0.25 0.20 0.20

Residual gas saturation 0.035 0.035 0.035

End-point water permeability 0.55 0.55 0.55

End-point oil permeability 0.80 0.80 0.80

End-point gas permeability 0.50 0.50 0.50

Corey exponent 2 2 2

1measured PVT value, 2estimated PVT value

Table 6-12 MBal reservoir input parameters

C1 C4 Iku 3 Iku 6 Ewi

2.1 Iku 3 Iku 6 Ewi

2.0 Ewi 2.1

SE STOIIP 15.1 8.6 18 SE STOIIP 15.1 8.6 4.1 36.6 NW STOIIP - - - NW STOIIP 9.9 8.3 - -

41.7 MMBO 82.6 MMBO

C5 C12 Iku 3 Iku 6 Ewi

2.1 Iku 3 Iku 6 Ewi

2.0 Ewi 2.1

SE STOIIP 16.1 11 18 SE STOIIP 16.1 11 4.1 36.6 NW STOIIP 9.9 8.3 - NW STOIIP 14.1 14.2 4 9.2

63.3 MMBO 109.3 MMBO

Table 6-13 – Developed STOIIP values within MBAL models



6.7. Integrated Production System Model

The created Prosper and MBal models were linked together using the GAP software package which enables the various reservoir and well nodal models to be interlinked with the constraints of the production facilities (pipelines, separator conditions etc). This enabled creation of production forecasts which honoured all the system constraints (reservoirwellfacility). GAP models were run for the 4 selected cases defined in the decision tree Figure 5-4 and shown in Figure 5-5, namely:

Minimum case 3 well development (case 1) Low case 4 well development (case 5) Mid (base) case 5 well development (case 4) High case 6 well development (case 12)

It was assumed that production starts flowing to a temporary Early Production System (EPS) comprising an FPSO or temporary production barge moored next to the wellhead, both with offshore loading. The early production phase is planned to both accelerate revenue streams and gather data to allow optimal sizing of the facilities. During the early production phase to the EPS a capacity constraint of 10,000 BFPD was assumed, with a facilities uptime of 85%. Once Middleton tie-in is accomplished, this capacity constraint was raised to 16,000 BFPD, which is current nominal Middleton capacity with an uptime of 90%. The timings assumed for the production forecasts outlined below:

Production beginning through the EPS Jan 2013. Production initiates with App 1 and Dev-1 from start up. This would necessitate drilling of the two wells from mid-2012.

Production to the EPS ceases end June 2014 after 18 months. The field is shut-in for four months during which time the Middleton facility is tied in and commissioned.

Production to Middleton commences Nov-2014.

Middleton inlet pressure was set as 100 psig, though wells were constrained to a maximum sandface drawdown limit, meaning that excessively high drawdowns did not occur during early field life (see Table 6-14). The same drawdown limits apply during the EPS phase.

Well Target Area Case 1 Case 4 Case 5 Case 12 App-1 Iku-3 NW - 100 psi 100 psi -

Iku-6 NW - 100 psi 100 psi - Ewinti 2.1 NW - - - 50 psi

Dev-1 Ewinti 2.1 SE 20/15 psi 20 psi 20/15 psi 20 psi

Dev-2 Iku-3 SE 50 psi 50 psi 50 psi 50 psi Dev-3 Iku-6 SE 20 psi 20 psi 20 psi 20 psi Dev-4 Ewinti 2.1 SE - 20 psi - 20 psi

Ewinti 2.0 SE - 50 psi - 50 psi Dev-5 Iku-6 NW - 20 psi - 20 psi

Dev-6z (S/T) Iku-3 NW - 50 psi - 50 psi

Table 6-14 – Sandface drawdown constraints applied to forecasts

Produced gas is assumed to be flared during the EPS phase. It is assumed that an 18 month licence to flare will be granted by governmental authorities; though this should be considered an uncertainty. In the event that a licence of 18 months duration is not



granted, sufficient data would have been gathered after a few months of production to size facilities. In this event, a longer field SI would occur between cessation of production to the EPS and commissioning of permanent facilities (Middleton tie-in). During full field development gas flaring will not be permitted, and it is assumed that gas will be injected into the Middleton Field using one of the existing, but shut in gas wells. Previous work proposed using the Middleton-2 well to inject into the Ekiti-3 reservoir. Table 6-15 shows a summary of the cases and associated recoverable volumes.

GAP case

Well Reservoir Area Date on

stream

Separator Pressure

psia

STOIIP (MMstb)

Recoverable volume at 1.1.2031

Recovery Factor

Case 1 Dev-1 Ew-2.1 SE P90 1/2013 100

42.7 4.776

12.31 0.28 Dev-2 Iku-3 SE P90 11/2014 100 5.247 Dev-3 Iku-6 SE P90 2/2015 100 2.284

Case 5

App-1 Iku-3 NW P50 1/2013 100

64.3

1.073

18.95 0.29 Iku-6 NW P50 1/2013 100 1.212

Dev-1 Ew-2.1 SE P90 1/2013 100 4.872 Dev-2 Iku-3 SE P10 1/2015 100 7.948 Dev-3 Iku-6 SE P10 4/2015 100 3.842

Case 4

App-1 Iku-3 NW P50 1/2013 100

82.6

1.023

25.13 0.30

Iku-6 NW P50 1/2013 100 1.051

Dev-1 Ew-2.1 SE P50 1/2013 100 6.879 Ew-2.0 SE P50 4/2020 100 1.216

Dev-2 Iku-3 SE P50 11/2014 100 7.927 Dev-3 Iku-6 SE P50 2/2015 100 3.276 Dev-4 Ew-2.1 SE P50 4/2015 100 3.758

Case 12

App-1 Ew-2.1 NW P10 1/2013 100

109.3

1.537

33.95 0.31

A-1 ST Ik-3 NW P10 8/2017 100 4.018 Dev-1 Ew-2.1 SE P50 1/2013 100 7.524 Dev-1 Ew-2.0 SE P50 7/2021 100 1.776 Dev-2 Iku-3 SE P10 11/2014 100 7.250 Dev-3 Iku-6 SE P10 2/2015 100 3.877 Dev-4 Ew-2.1 SE P50 4/2015 100 4.549 Dev-5 Iku-6 NW P10 6/2016 100 3.417

Table 6-15 Summary of GAP model recoverable volume scenarios

6.7.1. Base Case (Case 4) – 5 well development

In the base case (as described in Section 5.6), full field development produces 25.1 MMstb with 5 wells and 1 recompletion. The GAP Integrated Production System Model architecture is shown in Figure 6-2. Table 6-16 shows the technical recoverable volumes per drainage point to end 2030. Figure 6-3 shows the base case oil prediction profile per well, Figure 6-4 the production profile per reservoir and Figure 6-5 the field liquid stream profile. The forecasts shown in these figures were carried forward to economic evaluation.



Figure 6-2 – Case 4 Integrated Production System model

CASE 4 Developed STOIIP = 82.6

Area Well Target Well Completion Peak Oil

Max GOR

Max W/C

Cum Oil

BOPD scf/stb % MMstb NW App-1 Iku-3 Cased hole deviated dual (20' perf) 540 258 56 1.02 NW Iku-6 Cased hole deviated dual (10' perf) 367 297 12 1.05 SE Dev-1 Ewinti 2.1 Horizontal (500 m) 5,572 10,572 1 6.88 SE Ewinti 2.0 Cased hole recompletion (20' perf) 2,291 8,219 43 1.22 SE Dev-2 Iku-3 Horizontal (500 m) 3,118 246 51 7.93 SE Dev-3 Iku-6 Horizontal (500 m) 5,572 6,140 42 3.28 SE Dev-4 Ewinti 2.1 Horizontal (500 m) 1,193 10,605 1 3.76

Note: Perforated intervals refer to vertical ft not MD 25.1

Total RF 0.30 Iku-3 RF 0.36 Iku-6 RF 0.26

Ewinti 2.0 RF 0.29 Ewinti 2.1 RF 0.30

Table 6-16 – Case 4 recoverable volumes per reservoir unit to end-2030

The existing Middleton separator total liquids capacity of 16,000 bfpd is sufficient to produce the forecast volumes. Average field RF is 30%. The field is producing 700 BOPD at the end of the forecast period. The lowest recovery is experienced in the Iku-6 reservoir at 26%. The Ewinti 2.0 and 2.1 achieve ~30% recovery and the Iku-3 a 36% recovery. The high recovery factor and long production period in the Iku-3 reservoir is achieved by the assumption that the reservoir would receive some pressure support from the aquifer and that, within the model, a single horizontal well successfully drains the SE. If this support is weak and the reservoir is solely solution gas drive, then the stated recovery from the reservoir may drop substantially by some 2.7 MMstb (assuming a 25% RF in the Iku-3).



0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

01/2013

01/2014

01/2015

01/2016

01/2017

01/2018

01/2019

01/2020

01/2021

01/2022

01/2023

01/2024

01/2025

01/2026

01/2027

01/2028

01/2029

01/2030

01/2031

Oil Rate (BOPD)

Year

Sensitivity Case 4STOIIP = 82.6 MMSTB

100 psi separator pressure

Dev 1 (Ewinti 2.1) App LS (Iku‐6) App SS (Iku‐3) Dev 2 (Iku‐3) Dev 3 (Iku‐6) Dev 4 (Ewinti 2.1) Dev 1 Recompletion (Ewinti‐2.0)

Figure 6-3 - Base Case 4 Production Profile

Figure 6-4 Case 4 oil production per reservoir



0

5

10

15

20

25

30

35

0

2000

4000

6000

8000

10000

12000

14000

16000

Produced Gas (M

MSCFD

),Cum Oil (M

MBO)

Oil / Liquid / W

ater (BOPD)

Year

Case 4 Field Production by Liquid StreamOil (BOPD) Water (BWPD) Produced Gas (MMSCFD) Cum Oil (MMBO) Gas Lift Requirement (MMSCFD)

Figure 6-5 - Case 4 field production per liquid stream

With reference to Figure 6-4, it can be seen that with the drawdown constraint set, depletion of the Ewinti-2.1 reservoir occurs very rapidly within the model due to the very high reservoir PI. It may be beneficial that during development a lower drawdown constraint is set to reduce the reservoir off-take rate. This would lower the peak field rate and extend the plateau. Figure 6-7 shows an alternate field level production profile with Ewinti 2.1 maximum sandface drawdown reduced to 10 psi from 20 psi. This profile gives a longer off-take period for Ewinti 2.1 that may be better for reservoir management purposes and potentially lead to a higher UR in the Ewinti 2.1 reservoir.

Additionally, with reference to the field profile it can be seen that there is a fairly long tail to production; this being predominantly due to production from Iku-3 (within the forecast this reservoir still produces >600 BOPD at end-2030 from one drainage point). Depending on circumstances, there may be an opportunity to recomplete Dev-4 (Ewinti 2.1) to the Iku-3 at the same time as Dev-1 (Ewinti 2.1) is recompleted to the Ewinti 2.0. This would enable Iku-3 production to be accelerated and bring forward field abandonment. Alternatively a standalone additional drainage point in Iku-3 could be considered if there is a spare platform slot to drill a new well.

The gas lift requirement for the field is shown in Figure 6-5. The maximum total gas lift requirement is 15 MMscfd.



Figure 6-6 – Case 4 alternate Field profile with reduced drawdown

Figure 6-7 – Case 4 alternate profile with reduced drawdown production per reservoir

Should the Ewinti 2.1 crude have PVT properties as suggested by the Ekeh-2H well test results, then the PI may drop by up to some 50%. Assuming a 20 psi drawdown restriction on Ewinti 2.1, this equate to a field maximum average rate of ±9,800 BOPD (±7,000 BOPD assuming a 10 psi drawdown restriction on Ewinti 2.1). Recoverable volumes would remain similar.



6.7.2. Minimum Case (Case 1) – 3 well development

In Case 1 (as described in Section 6.4), limited development of the SE area only produces 12.3 MMstb with 3 wells. The GAP Integrated Production System Model architecture is shown in Figure 6-8. Table 6-17 shows the technical recoverable volumes per drainage point to end 2030. Figure 6-9 shows the base case oil prediction profile per well. Figure 6-10 the production profile per reservoir and Figure 6-11 the field liquid stream profile. The forecasts shown in these figures were carried forward to economic evaluation.

Figure 6-8 - Case 1 Integrated Production System model



Max GOR

Max W/C

Cum Oil

BOPD scf/stb % MMstb SE Dev-1 Ewinti 2.1 Horizontal (500 m) 4,984 18,433 8 4.78 SE Dev-2 Iku-3 Horizontal (500 m) 3,118 245 87 5.24 SE Dev-3 Iku-6 Horizontal (500 m) 1,090 16,000 41 2.28


Total RF 0.30 Iku‐3 RF 0.35

Iku‐6 RF 0.23

Ewinti 2.1 RF 0.27

Table 6-17 - Case 1 recoverable volumes per reservoir unit to end-2030

Within the forecast the field reaches a maximum rate of 8,000 BOPD. Field production drops below 500 BOPD by end-2023. During the EPS period, off-take from the Ewinti 2.1 reservoir is lowered as dynamic production data indicated a low case STOIIP (and a thinner oil column). Drawdown constraint is lowered to 15 psi, though as discussed in Section 6.7.1 there may be definitive benefit to lowering drawdown constraint to 10 psi.

Average field RF is 30%. The lowest recovery is experienced in the Iku-6 reservoir at 23% as the wells experience gas coning. The Ewinti 2.1 achieves 27% recovery. The high Iku-3 recovery of 35% is assisted by the assumption that the reservoir would receive some pressure support from the aquifer. If this support is weak and the reservoir



is solely solution gas drive, then the stated recovery from the reservoir may drop by some 1.5 MMstb (assuming a 25% RF in the Iku-3).

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

01/2013

01/2014

01/2015

01/2016

01/2017

01/2018

01/2019

01/2020

01/2021

01/2022

01/2023

01/2024

01/2025

01/2026

01/2027

01/2028

01/2029

01/2030

Oil Rate (BOPD)

Year



Dev 1 (Ewinti 2.1) Dev 2 (Iku‐3) Dev 3 (Iku‐6)

Figure 6-9 - Case 1 Production Profile

Figure 6-10 – Case 1 oil production per reservoir



0

5

10

15

20

25

30

35

0

2000

4000

6000

8000

10000

12000

14000

16000

01/2013

07/2013

01/2014

07/2014

01/2015

07/2015

01/2016

07/2016

01/2017

07/2017

01/2018

07/2018

01/2019

07/2019

01/2020

07/2020

01/2021

07/2021

01/2022

07/2022

01/2023

07/2023

01/2024

07/2024

01/2025

07/2025

01/2026

07/2026

01/2027

07/2027

01/2028

07/2028

01/2029

07/2029

01/2030

07/2030

01/2031

Produced Gas (M

MSCFD

),Cum Oil (M

MBO)

Oil / Liquid / W

ater (BOPD)

Year

Case 1 Field Production by Liquid StreamOil (BOPD) Water (BWPD) Produced Gas (MMSCFD) Cum Oil (MMBO)


In a downside situation, where the Middleton Production Platform is not available, or the cost of refurbishment is prohibitive, the EPS could potentially continue to produce oil provided government consent is given to continue to flare gas. However, the EPS operating costs are likely to result in early shut down of the field, and the recoverable volumes would be less than indicated.

Should the Ewinti 2.1 crude have PVT properties as suggested by the Ekeh-2H well test results, then the well PI may drop by up to some 50%. Assuming a 20 psi drawdown restriction on Ewinti 2.1, this equate to a field maximum average rate of ±6,200 BOPD (±5,200 BOPD assuming a 10 psi drawdown restriction on Ewinti 2.1). Recoverable volumes would remain similar.

6.7.3. Low Case (Case 5) – 4 well development

In Case 5 (as described in Section 5.5) the full field development produces 18.95 MMstb with 4 wells. The GAP Integrated Production System Model architecture is shown in Figure 6-12. Table 6-18 shows the technical recoverable volumes per drainage point to end 2030. Figure 6-3 shows the base case oil prediction profile by well, Figure 6-14 the production profile per reservoir and Figure 6-15 the field liquid stream profile. The forecasts shown in these figures were carried forward to economic evaluation.

Within the forecast the field reaches a maximum rate of <9,000 BOPD. Field production drops below 500 BOPD by mid-2029. During the EPS period, off-take from the Ewinti 2.1 reservoir is lowered as dynamic production data indicated a low case STOIIP (and a thinner oil column). Drawdown constraint is lowered to 15 psi, though as discussed in Section 6.7.1 there may be benefit to lowering drawdown constraint to 10 psi.




Table 6-18 - Case 5 recoverable volumes per reservoir unit to end-2030

Average field RF is 30%. The lowest recovery is experienced in the Iku-6 reservoir at 26%. The Ewinti 2.1 achieves 27% recovery and the Iku-3 35% recovery. The high recovery factor and long production period in the Iku-3 reservoir is achieved by the assumption that the reservoir would receive some pressure support from the aquifer and that, within the model, a single horizontal well successfully drains the SE. If this support is weak and the reservoir is solely solution gas drive, then the stated recovery from the reservoir may drop substantially by some 2.9 MMstb (assuming a 25% RF in the Iku-3). It is also recommended that budgeting accounts for at least one sidetrack in later field life to achieve the recoverable volumes stated in Table 6-18.



Max GOR

Max W/C

Cum Oil

BOPD scf/stb % MMstb

NW App‐1

Iku‐3 Cased hole deviated dual (20' perf) 539 257 57 1.07

NW Iku‐6 Cased hole deviated dual (10' perf) 327 297 4.5 1.21

SE Dev‐1 Ewinti 2.1 Horizontal (500 m) 4,988 15,623 4.6 4.87

SE Dev‐2 Iku‐3 Horizontal (500 m) 3,116 245 73 7.95

SE Dev‐3 Iku‐6 Horizontal (500 m) 1,072 7,109 36 3.84 Note: Perforated intervals refer to vertical ft not MD 18.95

Total RF 0.30

Iku‐3 RF 0.35

Iku‐6 RF 0.26

Ewinti 2.1 RF 0.27



0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

01/2013

07/2013

01/2014

07/2014

01/2015

07/2015

01/2016

07/2016

01/2017

07/2017

01/2018

07/2018

01/2019

07/2019

01/2020

07/2020

01/2021

07/2021

01/2022

07/2022

01/2023

07/2023

01/2024

07/2024

01/2025

07/2025

01/2026

07/2026

01/2027

07/2027

01/2028

07/2028

01/2029

07/2029

01/2030

07/2030

01/2031

Oil Rate (BOPD)

Year



Dev 1 (Ewinti 2.1) App LS (Iku‐6) App SS (Iku‐3) Dev 2 (Iku‐3) Dev 3 (Iku‐6)

Figure 6-13 - Case 5 Production Profile




0

5

10

15

20

25

30

35

0

2000

4000

6000

8000

10000

12000

14000

16000

Produced Gas (M

MSCFD

),Cum

Oil (MMBO)

Oil / Liquid / W

ater (BOPD)

Year

Case 5 Field Production by Liquid Stream

Oil (BOPD) Water (BWPD) Produced Gas (MMSCFD) Cum Oil (MMBO)


With reference to the field profile it can be seen that there is a fairly long tail to production; this being predominantly due to production from Iku-3. Depending on circumstances, it may be worth considering if Dev-1 or Dev-4 could be recompleted to the Iku-3 after the Ewinti 2.1 is depleted. This would enable Iku-3 production to be accelerated and bring forward field abandonment. Alternately a standalone additional drainage point in Iku-3 could be considered if there is a spare platform slot.


6.7.4. High (Case 12) – 6 well development

In Case 12 (as described in Section 5.7), full field development produces 33.9 MMstb with 5 wells, 1 sidetrack and 1 recompletion. The GAP Integrated Production System Model architecture is shown in Figure 6-16. Table 6-19 shows the technical recoverable volumes per drainage point to end 2030. Figure 6-17 shows the base case oil prediction profile roll-up, Figure 6-18 the production profile per reservoir and Figure 6-19 the field liquid stream profile. The forecasts shown in these figures were carried forward to economic evaluation.

The forecast was constrained to the Middleton nominal capacity of 16,000 BOPD and 10% downtime, yielding a short production plateau at 14,400 BOPD.

Average field RF is 31%. The field is producing 950 BOPD at end of forecast period. The lowest recovery is experienced in the Ewinti-2.0 reservoir at 22% which only has one drainage point in this development case. The Iku-6 and Ewinti 2.1 achieve improved recovery factors of 29% and 30% respectively.



The Ewinti 2.1 achieve and Iku-6 also have improved recoveries versus the base case of 30% and 37% respectively. The Ewinti 2.1 recovery could be improved by deferring the sidetrack of Appraisal 1 (as Dev 6z) to the Iku-3. This could be achieved by drilling a new well for Iku-3 if there is a spare platform slot. The high recovery factor of 37% and long production period in the Iku-3 reservoir is achieved by the assumption that the reservoir would receive some pressure support from the aquifer and that, within the model, two horizontal wells successfully drain the reservoir. If this support is weak and the reservoir is solely solution gas drive, then the stated recovery from the reservoir may drop significantly by some 3.7 MMstb (assuming a 25% RF in the Iku-3). It is recommended that budgeting accounts for at least two additional sidetracks in later field life to achieve the recoverable volumes stated in Table 6-19.




Max GOR

Max W/C

Cum Oil

BOPD scf/stb % MMstb NW App-1 Ewinti 2.1 Cased hole completion (20' perf) 1,234 442 0 1.54 SE Dev-1 Ewinti 2.1 Horizontal (500 m) 5,274 10,553 1 7.52 SE Dev-2 Iku-3 Horizontal (500 m) 3,119 245 35 7.25 SE Dev-3 Iku-6 Horizontal (500 m) 1,078 9,167 28 3.88 SE

Dev-4 Ewinti 2.1 Horizontal (500 m) 5,270 4,680 2 4.55

SE Ewinti 2.0 Cased hole recompletion (20' perf) 2,218 21,600 33 1.77 NW Dev-5 Iku-6 Horizontal (500 m) 1,077 7,179 9 3.41 NW Dev-6z

(S/T) Iku-3 Horizontal (500 m) 2,286 230 56 4.02


Total RF 0.30 Iku-3 RF 0.36 Iku-6 RF 0.26

Ewinti 2.0 RF 0.29 Ewinti 2.1 RF 0.30

Table 6-19 – Case 12 recoverable volumes per reservoir to end-2030



0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

01/2013

06/2013

11/2013

04/2014

09/2014

02/2015

07/2015

12/2015

05/2016

10/2016

03/2017

08/2017

01/2018

06/2018

11/2018

04/2019

09/2019

02/2020

07/2020

12/2020

05/2021

10/2021

03/2022

08/2022

01/2023

06/2023

11/2023

04/2024

09/2024

02/2025

07/2025

12/2025

05/2026

10/2026

03/2027

08/2027

01/2028

06/2028

11/2028

04/2029

09/2029

02/2030

07/2030

Oil Rate (BOPD)

Year



Dev 1 (Ewinti 2.1) App LS (Ewinti 2.1) App SS (Iku‐6) Dev 2 (Iku‐3) Dev 3 (Iku‐6)

Dev 4 (Ewinti 2.1) Dev 5 (Iku 6) Dev 6z (Iku 3) Dev 1 (Recompletion Ewinti 2.0)

Figure 6-17 - High Case 12 Production Profile




0

5

10

15

20

25

30

35

0

2000

4000

6000

8000

10000

12000

14000

16000

Produced Gas (M

MSCFD

),Cum Oil (M

MBO)

Oil / Liquid / W

ater (BOPD)

Year

Case 12 Field Production by Liquid StreamOil (BOPD) Water (BWPD) Produced Gas (MMSCFD) Cum Oil (MMBO)


With reference to Figure 6-18 it can be seen that with the drawdown constraint set, depletion of the Ewinti-2.1 reservoir occurs very rapidly within the model due to the very high reservoir PI. It may be beneficial that during development a lower drawdown constraint set to reduce reservoir off-take rate. This would lower the peak field rate and extend the plateau.

Additionally, with reference to the field profile it can be seen that there is a fairly long tail to production; this being predominantly due to production from Iku-3 (within the forecast this reservoir still produces >600 BOPD end-2030 from one drainage point). It is worth considering if Dev-4 (Ewinti 2.1) can be recompleted to the Iku-3 at the same time as Dev-1 (Ewinti 2.1) is recompleted to the Ewinti 2.0. This would enable Iku-3 production to be accelerated and bring forward field abandonment. Alternately a standalone additional drainage point in Iku-3 could be considered if there is a spare platform slot.




6.7.5. Risks and uncertainties in reservoir modelling and development assumptions

The reservoir modelling has required some assumptions to be made due to the lack of some critical data. Permeability has not been defined. No core samples were taken and no core analyses were performed. Estimation of reservoir permeability from the well tests is not possible as no data was acquired to allow pressure transient analysis. Fluid compositions are uncertain, and appear to be different in the different reservoirs, and PVT samples need to be taken for the Iku-6 and Ewinti 2.1. Should crude in the Ewinti 2.1 reservoir be heavier and more viscous than suggested by the Ewinti 2.1 well test, this will have an impact on achievable peak field rates.

Special core analysis is required to estimate water saturation and relative permeability values for each fluid. Reservoir pressure remains uncertain, and interconnectivity across the field is unknown. The GAP models assumed that there is pressure connection between the NW and SE areas and this may not be the case. It is also recommended that the Appraisal-1 well establish initial reservoir pressure for each zone and then subsequently perform a suitably designed drawdown and build-up test on each discovered reservoir zone to enable reservoir depletion behaviour to be established.

Once additional sub-surface data is gathered for each reservoir zone, a full field static geological model should be built and exported to a dynamic simulation tool. Full field dynamic simulation modelling should be undertaken to enable final well placement to be selected for each reservoir and associated reservoir/field recoveries to be predicted. Fine grid cell sector modelling should be undertaken to investigate critical drawdown rates for the Iku-6 and Ewinti 2.1 reservoir.

The Ewinti formation has been developed in neighbouring fields offshore Nigeria, e.g. Middleton. Based on a review of the available information regarding the Middleton field development project there is evidence that the reservoir pressure in Ewinti-2.1 reservoir dropped significantly over a short period of time exhibiting high pressure decline rates. This could happen to Ekeh if gas cap breakthrough occurs, resulting in high gas production rates, reservoir depressurisation and rapid decline in oil production within the Iku-6 and Ewinti 2.1 reservoirs. To mitigate against this, the horizontal production section needs to be drilled at an optimum depth datum between the GOC and the OWC. The NW appraisal well (App-1) should provide some information to constrain the OWC in the Ewinti-2.1, and should therefore be drilled before Dev-1.

Whilst the reservoir modelling indicates viable development scenarios, these are all predicated on the availability and usability of the Middleton Production Platform for processing facilities, export facilities and at least one Middleton well for gas injection and gas lift supply. The platform has been out of service for 8 years, and is known to have been damaged. The condition of the Middleton wells and export pipeline is not known. However, both these risks will be substantially quantified by the pending inspection of the Middleton Production Platform which will provide a full engineering base-line survey for MRI and Movido.

If the Middleton facilities cannot be made serviceable, alternative development scenarios would need to be examined, such as constructing a new full facilities platform, or using an FPSO. This is likely to incur extra cost, including the cost of a gas disposal well and tie-in to an alternate an oil export system; most likely Pennington.



7. Field Development Concept

7.1. Overview

The Ekeh field is currently in an early stage of appraisal, and a better understanding of recoverable volumes and production potential are required before a field development plan can be optimised. It is therefore planned to further appraise the field and conduct a long term production test to ascertain requirements for well numbers, pipeline sizing, platform sizing and processing capacity. This will be achieved through a long term production test via an Early Production Scheme (EPS) prior to defining facilities requirements for the refurbishment of Middleton Production Platform and construction of permanent Ekeh Platform facilities. The following conceptual development concepts illustrate the various development configurations that might be required.

Figure 7-1 Ekeh Location Map



7.2. Wells

7.2.1. Ekeh-1 and -2H

Two previous wells have been drilled in the Ekeh field, the Ekeh-1 and Ekeh-2H wells. Ekeh-1 was a deviated exploration well that penetrated the Ewinti-2.1 reservoir and was subsequently abandoned below the mudline and no longer usable as a future producer. It is assumed that this well is plugged and abandoned.

Ekeh-2H well was planned as a dual completion well with a horizontal section in the Ewinti-2.1 and a second completion on the Iku-6. The drilling of this well encountered significant problems including failure to run the liner to bottom, partial recovery of the failed liner, and failure to repair and reconnect the liner. Although the well was partially tested, the well is not in a safe condition to be used as a producer. It also appears to have been hit by shipping, leaving the casing protruding from the sea at an angle of 15 degrees. In its present condition it is no longer considered useable as a producer.

Is should be noted that the most recent activity on the Ekeh-2H well occurred in Feb 2010 when a coil tubing clean out was attempted. During the attempted clean-out a mixture of sea water, diesel and nitrogen was pumped. At the end of the intervention activity surface pressure on the SCSSV was bled off to actuate a tubing close. No kill weight brine was circulated and no physical plugs were set in any of the nipples or SCSSV. The well remains unsuspended. It is unknown if the intervention occurred before or after the incident which bent the conductor, but a number of heavy ships were involved in the workover.

Figure 7-2 Ekeh-2H Well head, xmass tree and conductor

Given that the well is not suspended and requires temporary abandonment at the very least; and more likely plug and abandonment, it should be considered a considerable



liability in its current state. It is recommended that the Ekeh-2 well is plugged and abandoned in the early drilling phase when Appraisal 1 and Dev-1 are drilled. Given the mechanical state of the well, specialist equipment is likely to be required and abandonment procedures will be made complex than a simple P&A activity. A detailed evaluation of Ekeh-2H abandonment requirements has not been made as part of this study. It is however recommended that additional provision is made for abandonment of this particular over and above the anticipated abandonment costs of further field wells.

7.2.2. Proposed New Well Design

Development of the Ekeh Field will use predominantly horizontal wells with gravel pack completions to maintain the wellbore and remove the risk of early wellbore failure and erosion through sand production. The exception to this would be the App-1 appraisal well in the NW of the field which needs to test for hydrocarbons in at least three reservoirs, and will therefore be a deviated well, although it may be sidetracked later to provide a horizontal completion in one reservoir.

The well construction will be of simple design to achieve the production targets and would utilise oil based mud and rotary steerable drilling systems to achieve these goals.

The wells would use a 36” Conductor hammered into the seabed followed by 30” casing; a 17 ½” tophole section, drilled with water based mud and set with 13 3/8” casing; a 12 ½” deviated build-up section drilled with oil based mud (OBM) and set with 9 5/8” casing; and a 8 ½” horizontal reservoir section drilled with OBM and completed with an open hole gravel pack.

7.2.3. Well Costs

Three generic well designs have been used for well cost estimation using AGR’s P1 well planning software:

Vertical Appraisal well with dual completion: $14 million

Horizontal Production well with single gravel pack completion: $9 million

Deviated pilot hole, plugged back, followed by a Horizontal Production well with single completion: $10 million.

7.2.4. Completion Design

The Completion philosophy for the Ekeh field is specified as follows:

Dry trees with intervention via slickline, wireline and coil tubing supported from a wellhead jacket

Reservoirs completed separately to facilitate best reservoir management practices Control sand production downhole Maximise off-take rate while minimising reservoir drawdown Enable options for dual completion where appropriate Minimise well completion complexity Robust completion design that requires minimum rig based intervention

To meet the stated design objectives, the completion design for the Ekeh field may be summarised:

Reservoirs will be completed separately as dedicated drainage points. Commingling will not form part of the initial development strategy and well completion design.

Horizontal wells are the primary development choice. Drain lengths of 250m or greater are envisaged. Horizontal wells will be completed in 8.5” hole (though 7” hole would achieve similar rates).



Cased and perforated completions in vertical/deviated holes are an option for secondary targets. Where possible the lower target should be completed horizontally.

Sand control will be required in all production wells. Premium sand screens or gravel packs should be run on initial completion.

Horizontal wells will be completed with 4.5” tubing. Where two zones are completed in a dual completion, 3.5” tubing will make the Long String (lower zone) and 2.875” tubing the Short String (upper zone).

Ekeh fluids are reportedly sweet with little or no H2S, therefore standard completion materials can be used.

Previous reports mention no wax and asphaltenes issues. The completion design has the capacity to run chemical injection lines and an injection port.

Gas lift mandrels will be run with the initial completion for all wells. Downhole permanent pressure gauges should be run with all completions (note

however that running downhole pressure gauges on both the Short and Long string in dual completions will be unduly complex).

Strong preference is given to drilling dedicated single string completion wells. This makes well completion far less complex; particularly when sand control is required on both reservoirs. Additionally, when drilled in horizontal geometry the PI of the wells for all reservoirs would fully utilise the capacity of 4.5” tubing. When dual completions are selected, where possible the lower completion should be landed in horizontal well geometry. No core samples were available for laboratory analysis to determine sorting and grain size distribution; therefore screen and mesh sizing was not possible. Test results from Ekeh-2H and known sanding tendencies from offset fields indicate that sand will be produced from initial production in Ekeh, and hence sand exclusion will be required.

Table 7-1 shows a tabulated completion specification for Ekeh production wells as per the Scenarios outlined within this report (development Cases).

Area Well Target Case Well Completion String Tubing OD Completion GL SPM DH Guage Chem Inj Pt

NW Iku‐3 4,5 Cased hole perforated dual1

Short String 2.875" Screens or GP Yes Yes2

TBI

NW Eku‐6 4,5 Cased hole perforated dual1

Long String 3.5" Screens or GP Yes Yes TBI

NW Ewinti 2.1 12 Cased hole perforated Single string 4.5" Screens or GP Yes Yes TBI

SE Dev‐1 Ewinti 2.1 1,4,5,12 Horizonta l (500 m) Single string 4.5" Screens or GP Yes Yes TBI

SE Dev‐2 Iku‐3 1,4,5,12 Horizonta l (500 m) Single string 4.5" Screens or GP Yes Yes TBI

SE Dev‐3 Iku‐6 1,4,5,12 Horizonta l (500 m) Single string 4.5" Screens or GP Yes Yes TBI

SE Ewinti 2.1 4,12 Horizonta l (500 m) Single string 4.5" Screens or GP Yes Yes TBI

SE Ewinti 2.0 4,12 Cased hole perf recompletion3 Single string 4.5" Screens or GP Yes Yes TBI

NW Dev‐5 Iku‐6 12 Horizonta l (500 m) Single string 4.5" Screens or GP Yes Yes TBI

NW Dev‐6z3 Iku‐3 12 Horizonta l (500 m) Single string 4.5" Screens or GP Yes Yes TBI

Note: Perforated interva ls refer to vertica l ft not MD1A dual s tring completion assumes that the appra isa l i s dri l led with 9 5/8" reservoir section. If a 8 1/2" hole section i s dri l led and cased 7", then

the tabulated completion i s not poss ible. In the smal ler hole des ign, the zones would be produced sequentia l ly. 2If running two data cables unduly problamatic, then do not run for Long String (pressure monitoring of Eku‐6 more cri tica l )3Sequentia l upward recompletion 4Appra isa l s idetrack or new dedicated horizonta l wel l

GP = Gravel Pack, GL = Gas Li ft, SPM = Side Pocket Mandrel , DH = Downhole, TBI = To Be Identi fied

Dev‐4

App‐1

Table 7-1 – Completion specification for Ekeh production wells

7.2.4.1. Gas Lift

Gas Lift will be used to cost effectively unload the well at the initial completion and therefore the flow lines will be required to be installed prior to the rig leaving the platform. Dependent upon final Middleton required inlet pressure, gas lift may be required from initial production on the Iku-3 and Iku-6 reservoirs. Gas lift mandrels will be installed in the initial completions to allow the wells to be unloaded and kicked off following shut–ins.



During the first 3 years of field production total gas rates will be between 3–4 MMscfpd. A portion of this will be used for power generation. If gas lift is required for all wells from start-up (this being dependent upon Middleton inlet pressure); then total initial gas lift requirement could be up to 20 MMscfpd. Therefore a source of makeup gas will be required from start-up; compression will be required to be planned as part of the platform refurbishment. A pipeline of sufficient capacity must be laid to transport the compressed gas from the Middleton Production Platform the Ekeh field well head jacket for gas lift injection (possibly 6”). It is understood that a gas supply is available for utilisation at the Middleton field. This well could be used as a swing producer with excess produced gas being disposed through injection.

7.3. Platform and Processing Facilities

7.3.1. Early Production Scheme (EPS)

Long term production testing during the initial phase of production from the Ekeh field could be achieved by the use of either a rented well testing barge or an FPSO.

A typical well test barge comprises standard well testing equipment installed on a jack-up barge. In addition to the well test barge, the EPS production spread will include a storage vessel, a support vessel (JTF), a supply vessel, a crew boat, an off-take vessel along with all moorings. This type of vessel is in common use in Nigeria, but can present problems with mooring and oil spillages. A schematic of this EPS scheme is shown in Figure 7-3. The use of an FPSO, with full production and storage facilities is a more expensive, but simpler operation, and again uses proven technology. A schematic of this EPS scheme variant is shown in Figure 7-4.

In either case, production capacity of about ±6,000 bopd would be required, and permitting would be required for gas flaring during the EPS stage. Standard capacity for and EPS vessel would be circa. 10,000 bfpd; and this would meet capacity requirements with some spare capacity.

Figure 7-3 Platform Barge based Early Production System



Figure 7-4 – FPSO based Early Production System

7.3.2. Wellhead Platform

For the full field development, a caisson type 3 leg wellhead platform (WHP) concept is proposed to be installed at Ekeh Field, tied back to processing facilities at Middleton Production Platform. A schematic of the full field development concept is shown in Figure 7-5.

Figure 7-5 – Full field development scheme

The drill rig will initially install a drilling template on the seabed. Through this the conductors for the wells and docking piles will be installed. The docking piles will be used to locate the future WHP jacket relative to the wells. The first 2 wells would be drilled with a jack-up drilling rig without the restriction of having the WHP installed first.

Following successful long term production testing pursuant to the EPS, the WHP will be installed before drilling further development wells from the platform.



The base case development assumes 5 production wells, but depending on the appraisal results, the platform could require up to 8 slots including 6 or 7 for wells and one for conductor pipe used for gaslift.

The WHP will have minimum facilities consisting of a production and test manifold, chemical injection, multiphase metering equipment and accessories on the topsides part. Multiphase fluids will be sent via a flowline to processing facilities at Middleton Production Platform. It is envisaged that a 6” line will meet capacity requirements, but pipeline sizing will follow from appraisal results. There will also be a 4” test line, and a gas lift line bringing compressed gas from Middleton Production Platform. The Ekeh platform would be remotely controlled from Middleton using a SCADA system.

7.3.3. Middleton Production Facilities

The Middleton Field was discovered in May 1972 by Middleton-1. Middleton was developed with 12 wells from a 4-legged steel piled jacket with oil separation and accommodation facilities. The field comprises 6 oil bearing reservoirs which produced a total of 28 MMstb up to December 1998 after which production continued at low levels until September 2003 when it was attacked, and damaged. The facility was last inspected in detail in 2008 by the current owners, when significant damage to equipment was filmed and reported. A new inspection is scheduled for 2011 to determine the platform condition and refurbishment requirements as part of any full field development plan.

The Middleton Production Platform facilities were designed for a liquid flowrate of 16,000 bpd (total liquids). The testing equipment (test header and test separator) is designed for 6,000 bpd (total liquids). Produced, stabilised oil was metered and exported. Gas was previously flared, but in future development scenarios this will not be permitted, and it is planned to inject Ekeh gas into one of the Middleton reservoirs, probably the Ekiti-3 using the M-2 well.

Produced water (15,000 bwpd capacity) was cleaned by hydrocyclones and disposed overboard. Platform utilities included gas and diesel power generators, fiscal metering, and accommodation.

Figure 7-6 Middleton Production Platform



The current physical condition and usability of the Middleton Production Platform is uncertain, and requires an baseline engineering inspection and refurbishment plan.

For the purpose of this evaluation, and until the planned Middleton Production Platform inspection is completed the following critical assumptions are made:

The separation vessels and piping can be re-used. Instruments and valves to be exchanged.

Structural repair works are required. Refurbishment of Lease Automatic Custody Transfer (LACT) unit will be as

described in the inspection report. All rotating equipment (pumps, generators), the entire electrical, instrumentation

and control system, fire fighting equipment as well as life capsule need to be replaced.

Major repair works are required on the living quarters.

Additional equipment for gas injection, lift gas supply and water injection shall be considered. Water injection equipment will include 2 x 100% reciprocating pumps as well as all piping with valves and filters, and typical chemical injection units. For gas injection, 1.0 Mscf/stb was assumed at 1,200 psig injection pressure.

7.3.4. Pipelines & Export

Two export routes exist from the Middleton Production Platform. There is an 8” export pipeline routed to the Oloibiri FPSO terminal and a 6” export pipeline to the Pennington FPSO terminal. It is MRI’s intention to export crude oil through the 6” export pipeline to Pennington FPSO terminal. The inspection carried out in 2008 indicated that the pipeline only needs to be flushed with water prior to pressure testing. This needs to be reconfirmed. Some piping will also have to be installed to hook the 6” export line up to the existing pig launcher. Figure 7-7 shows a schematic of area infrastructure and fields.

Madu

Anyaia

Sengana

Okubie

Middleton

Pennington Field

Pennington Terminal

Funiwa

Apoi

Bilabri‐Oribiri

EH

Bol

Chioma

Akarino

Ato

EKEH

27.5 km 10 ¾” pipeline

20.6 km 6 5/8” pipeline

NIGERIA

Key

Pipeline

Oil Field

Gas Field

Figure 7-7 – Are infrastructure and fields



8. Field Development and Operating Costs Conceptual Development and Operating Costs have been estimated for the 4 selected cases representing the minimum, low, base and high cases described above. In all cases, the development is phased, starting with the drilling of deviated App-1 appraisal well in the NW, and Dev-1 horizontal development well in the Ewinti-2.1 in the SE area. The rig will also be used to abandon the Ekeh-2 exploration well which is currently temporarily suspended.

These 2 wells will be hooked up to a floating Early Production Scheme (EPS) (a barge with oil production capacity of 10,000 bopd) which will export oil via shuttle tanker, flare any produced gas, and dispose of produced water overboard after cleaning. The EPS phase will initially last for 6 months, during which appraisal information will be gathered, and an optimal development plan prepared. After 6 months, the partners will approve a full field development plan. During the following 12 months, the EPS will continue producing whilst a new Ekeh Platform is procured and constructed. Production will cease for about 4 months whilst the platform is installed, together with pipelines to Middleton Production Platform. A rig will be needed to temporarily suspend the early producer wells, and drill the new development wells. One or more of the new development wells could either be drilled during the installation shutdown, or after the platform has been commissioned.

The two producing wells will be tied in to the new Ekeh platform, and production will recommence, with 3 phase (oil, gas & water) export to Middleton Production Platform where fluids will be processed. Oil will be exported via the existing export pipeline to the Pennington export terminal, where the oil will be sold. Separated gas will be reinjected into one of the Middleton gas reservoirs, and will be available to support gas lift, and later in field life possible gas production. Additional wells will then be drilled to complete the development of Ekeh Field. The number of wells will depend on the results of the appraisal programme. We have described below 4 cases representing the 3, 4, 5, and 6 well development cases.

8.1. Development Capital Expenditure

8.1.1. Minimum Development Case – 3 well development

The minimum case development assumes that App-1 fails to find any producible hydrocarbons, and is suspended. In this case recoverable volumes will be limited to the SE area and it is likely that the Ewinti-2.1 has a shallow OWC, and hence is developed by only 1 well. After the Ekeh platform is installed, the 2 remaining development wells are drilled in the Iku-3 and Iku-6. The full field development comprises only 3 wells. Ekeh-2H is abandoned upfront and remaining wells at the end of field life.

Assuming the farm-in is concluded in 2011, and tendering can start in early 2012, drilling will start as soon as planning is completed and a suitable drilling unit available – estimated to be in 2012, with EPS production starting in late 2012 / early 2013, and full field production starting in 2014. For economic modelling, it is assumed production will continue until end 2030. However, the reservoirs have the potential to continue producing beyond this at low rates.

Development Capital totals $77.2 million (Table 8-1). Well costs are expected to be $7 million for the suspended appraisal well (App-1), $9 million for the single completion horizontal producer Dev-1, and $10 million for the horizontal producer Dev-3 with the pilot hole to test the deeper Ewinti-2.1. $5 million is budgeted for abandonment of Ekeh-2. Facilities CAPEX totals $29.7 million. The Middleton Production Platform refurbishment and upgrade is provisionally budgeted for $10.5 million. These costs will be refined after the platform has been inspected, and work requirements are confirmed. The Ekeh



Platform is budgeted for $10 million, with a further $9.2 million for pipelines and controls.

During field life, additional Capital will be required for well interventions at irregular points. A Capital maintenance allowance of $0.9 million per year is budgeted to cover intermittent workover requirements. Abandonment CAPEX is estimated at $12.6 million to include the Ekeh and Middleton Production Platforms, the pipelines from Ekeh to Middleton, Ekeh-2H, plus the 4 new wells.

The risk facing this minimum downside scenario is for production from Dev-1 to be much worse than expected, perhaps due to rapid gas cap breakthrough which could result in the full field development appearing uneconomic, resulting in the decision not to install the new platform and drill additional wells. In this case, Dev-1 might be kept producing via the EPS until it is no longer economic or permitted to do so.

8.1.2. Low Case 5 – 4 well development

The low case is very similar to the minimum case, except that App-1 is able to produce some oil and the cost is expected to be $14 million for dual completion of this well. However, the results of App-1 indicate that the in place volumes are on the low side, with the Ewinti-2.1 having a shallow OWC, and hence the further development is the same as in the minimum case with a wellhead platform installed and 2 further wells being drilled. Recoverable volumes are higher however, due to contribution from App-1. App-1 well costs are higher due to the completion of the well, but platform costs are otherwise the same. Total development CAPEX is thus $84.2 million (Table 8-2). The capital maintenance allowance is increased to $1 million per year, and abandonment costs are $12.6 million, as in case 1. Ekeh-2H is abandoned upfront as it cannot be reused, and the producer wells are abandoned at the end of field life.

With a successful test of App-1 the development risks for Ekeh will be lower, as long term test data will be available from all three main reservoirs, providing some degree of security to proceed to the full development stage.

8.1.3. Base Case 4 – 5 well development

In the base case, robust Iku volumes are demonstrated by App-1, and an OWC is observed in the Ewinti-2.1 sufficiently deep for a second well to be drilled in the Ewinti-2.1, resulting in a 5 well development. The development costs are essentially the same as in the low case, with the exception of the additional well, Dev-4. However, there is a possibility that the Middleton facilities will need to be upgraded to increase capacity. However, as modelled, the wells can be managed to utilise the existing capacity. The development cost totals $93.2 million (Table 8-3), reflecting the additional 5th well, and capital maintenance and abandonment costs are increased to reflect this. A late stage recompletion of Dev-1 on the Ewinti-2.0 is included for $5 million. Ekeh-2H is abandoned upfront for $5 million and remaining wells at the end of field life.

8.1.4. High Case 12 – 6 well development

In the high case model, the facilities development is essentially the same as the base case, but an extra well is drilled, pushing total development CAPEX to $102.2 million (Table 8-4). Production could be capacity constrained however, and a larger capacity separator may be required on Middleton. As the actual Middleton capacity and refurbishment requirements are yet to be determined, we have modelled the same facilities work, but note the risk of additional upgrade costs to achieve the peak production rates achievable with a 6 well development. There is an additional $8 million budgeted for a sidetrack of App-1 to complete as a horizontal producer in the Iku-3 in 2016, followed by a further $5 million for recompletion of Dev-1 onto the Ewinti-2.0 in 2021. The annual capital maintenance allowance increased to $1.2 million, and abandonment increased to $15.6 million due to the additional well. Ekeh-2H is abandoned upfront and remaining wells at the end of field life.



8.2. Field Operating Costs Field Operating Costs (OPEX) during the EPS stage will depend upon the EPS vessel chosen, the basis of use (purchase or lease) and market conditions at the time of tendering. It is anticipated that the rental of a testing barge, and associated support vessels will cost about $27 million per year. If an FPSO is used the costs may be higher.

Operating costs using a well test barge are included in cost estimations in Table 8-1 to Table 8-4.

Once the platform is installed, Field OPEX will drop to around $5.3 million per year, though there would also be fees to pay to Chevron for the use of the Middleton Production Platform which could be in the order of $6-10 million per year.

8.3. Tariff Costs Some form of tariff costs for use of the Middleton Production Platform, a gas injection well, and export facilities will be agreed upon novation of the Ekeh Farm-out Agreement with Chevron. The existing (but expired) agreement, which assumed a fully working Middleton Production Platform being available included a fee of $1.75 per bpd of capacity used (annually escalated).

Because Ekeh partners will now have to refurbish the platform, for the purpose of economic modelling it has been assumed that MRI will pay the capital cost for refurbishment of the platform, and will then pay a $1.75 per barrel throughput tariff.

Project economics need to be reviewed following the renegotiation of the Middleton Production Platform Lease Agreement should there be any change in the capacity usage fee or other pertinent terms and conditions of the lease.

It is expected that oil will be sold FOB to Chevron or another credit-worthy offtake counter-party at Pennington terminal.



Year Total, $m 2011 2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019 2019 2020 2020 2021 2021 2022 2022 2023 2023 2024 2024 2025 2025 2026 2026 2027 2027 2028 2028 2029 2029 2030 2030 2031Capex H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2G&A, onshore project team 7.5 0.5 1.0 1.0 1.0 1.0 1.0 1.0 1.0Drill & Complete App-1, dry hole 7.0 7.0Drill & Complete Dev-1, Ewinti 2.1 9.0 9.0Middleton export facilities refurbishment 0.4 0.4Mooring, hoses, floats 0.2 0.2Engineering for refurb of Middleton 0.2 0.1 0.1Refurbish Middleton platform 5.4 2.7 2.7Ekeh MFP wellhead platform 10.0 5.0 5.0Pipelines 9.2 3.2 6.0Gas Re-injection facilities 3.8 1.8 2.0Water Disposal facilities 0.5 0.2 0.3Drill & Complete Dev-2, Iku-3 9.0 9.0Drill & Complete Dev-3, Iku-6 10.0 10.0Well Abandonments (5) 11.0 5.0 6Facilities Abandonment 1.6 1.6Capital Maintenence Allowance 21.2 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0

Capex total, $m Real 106.0 0.5 1.0 13.6 10.0 1.1 13.9 36.0 1.0 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.6Cum capex, $m Real 106.0 0.5 1.5 15.1 25.1 26.2 40.2 76.2 77.2 77.2 78.2 79.1 80.1 81.0 82.0 83.0 83.9 84.9 85.9 86.8 87.8 88.8 89.7 90.7 91.7 92.6 93.6 94.6 95.5 96.5 97.5 98.4 98.4 98.4 98.4 98.4 98.4 98.4 98.4 98.4 106.0Production MMBBLS ReservesApp-1, b/d 0.00Dev-1, b/d 4.82 4,983 3,743 3,736 1,319 3,970 3,944 2,896 685 311 194 119 78 49 28 0 0 0 24 20 15 10 3 92 48 1 24 34 24 18 14 10 9 4 7 3 4Dev-2, b/d 5.24 1,039 3,070 2,946 2,123 2,411 2,337 2,002 1,700 1,451 1,238 1,079 937 850 872 818 795 770 742 769 134 144 246 93 51 33 23 17 13 11 7 7 5 5Dev-3, b/d 2.28 902 1,074 1,074 1,072 1,066 1,057 1,046 1,030 1,010 984 917 627 345 84 38 23 14 5 49 33 4 13 13 9 6 5 4 3 1 2 1 2Spare 0.00Spare 0.00Total, b/d 12.350 0 0 0 4,983 3,743 3,736 2,358 7,942 7,964 6,093 4,169 3,714 3,252 2,865 2,558 2,296 2,092 1,854 1,477 1,217 926 852 808 766 778 275 224 251 130 98 66 48 36 26 23 12 16 10 10OpexLease of EPF, 6 months 19.6 6.5 6.5 6.5Lease of Storage Vessel, 6 months 6.0 2.0 2.0 2.0Export Facilities, 6 months 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Support Vessel, JTF, 6 months 59.3 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Supply Vessel, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Crew Boat, 6 months 8.4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Fuel & Lubricants, 6 months 25.3 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7Water, 6 months 5.6 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Feeding & berths, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Pilotage & Clearance, 6 months 9.8 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3Offtake Vessel, 6 months 33.7 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9Production Facilities Maint, 6 months 4.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1Pipelines Maint, 6 months 1.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Wellhead Platform Maint, 6 months 5.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Opex total, $m Real Total 0.0 0.0 0.0 13.5 13.5 13.5 4.9 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3

Phase 1 Phase 2a Phase 3a

Table 8-1 Minimum Case 1 – 3 well development CAPEX and OPEX Forecast



Year Total 2011 2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019 2019 2020 2020 2021 2021 2022 2022 2023 2023 2024 2024 2025 2025 2026 2026 2027 2027 2028 2028 2029 2029 2030 2030 2031Capex $MM H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2G&A, onshore project team 7.5 0.5 1.0 1.0 1.0 1.0 1.0 1.0 1.0Drill & Complete App-1, Iku-3 & Iku-6 14.0 14.0Drill & Complete Dev-1, Ewinti 2.1 9.0 9.0Middleton export facilities refurbishment 0.4 0.4Mooring, hoses, floats 0.2 0.2Engineering for refurb of Middleton 0.2 0.1 0.1Refurbish Middleton platform 5.4 2.7 2.7Ekeh MFP wellhead platform 10.0 5.0 5.0Pipelines 9.2 3.2 6.0Gas Re-injection facilities 3.8 1.8 2.0Water Disposal facilities 0.5 0.2 0.3Drill & Complete Dev-2, Iku-3 9.0 9.0Drill & Complete Dev-3, Iku-6 10.0 10.0Well Abandonments (5) 11.0 5.0 6Facilities Abandonment 1.6 1.6Capital Maintenence Allowance 23.2 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Capex total, $m Real 114.9 0.5 1.0 20.6 10.0 1.1 13.9 36.0 1.0 0.0 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7.6Cum capex, $m Real 114.9 0.5 1.5 22.1 32.1 33.2 47.2 83.2 84.2 84.2 85.2 86.3 87.3 88.4 89.5 90.5 91.6 92.6 93.7 94.7 95.8 96.8 97.9 98.9 100.0 101.0 102.1 103.1 104.2 105.2 106.3 107.3 107.3 107.3 107.3 107.3 107.3 107.3 107.3 107.3 114.9Production MMBBLS ReservesApp-1, b/d 2.31 833 833 831 415 872 830 785 761 722 684 648 615 568 515 467 414 391 372 382 326 287 113 0 0 0 0 0 0 0 0 0 0 0 0 0 0Dev-1, b/d 5.10 5,058 3,797 3,794 1,896 4,003 3,988 3,083 879 324 156 102 77 63 53 45 41 26 9 0 0 0 0 104 81 83 55 34 21 14 9 7 4 1 51 15 52Dev-2, b/d 7.80 0.0 0.0 0 0 3,124 3,041 2,425 2,524 2,807 2,647 2,347 2,060 1,813 1,605 1,428 1,284 1,154 1,060 980 866 770 773 835 855 877 866 845 821 798 775 754 733 893 331 458 210Dev-3, b/d 3.74 0.0 0.0 0 0 544 1,088 1,094 1,094 1,092 1,092 1,091 1,090 1,089 1,087 1,085 1,084 1,081 1,078 1,165 1,052 1,010 988 603 305 208 129 83 54 37 25 18 12 4 45 15 49Total, b/d 18.950 5,891 4,629 4,626 2,312 8,543 8,948 7,387 5,257 4,946 4,579 4,188 3,843 3,533 3,261 3,026 2,824 2,652 2,518 2,527 2,244 2,067 1,874 1,542 1,241 1,167 1,049 962 897 848 809 778 749 897 427 488 310

OpexLease of EPF, 6 months 19.6 6.5 6.5 6.5Lease of Storage Vessel, 6 months 6.0 2.0 2.0 2.0Export Facilities, 6 months 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Support Vessel, JTF, 6 months 59.3 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Supply Vessel, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Crew Boat, 6 months 8.4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Fuel & Lubricants, 6 months 25.3 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7Water, 6 months 5.6 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Feeding & berths, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Pilotage & Clearance, 6 months 9.8 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3Offtake Vessel, 6 months 33.7 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9Production Facilities Maint, 6 months 4.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1Pipelines Maint, 6 months 1.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Wellhead Platform Maint, 6 months 5.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Total 0.0 0.0 0.0 13.5 13.5 13.5 4.9 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3


Table 8-2 Low Case 5 – 4 well development CAPEX and OPEX Forecast



Year Total 2011 2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019 2019 2020 2020 2021 2021 2022 2022 2023 2023 2024 2024 2025 2025 2026 2026 2027 2027 2028 2028 2029 2029 2030 2030 2030Capex $MM H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2G&A, onshore project team 7.5 0.5 1.0 1.0 1.0 1.0 1.0 1.0 1.0Drill & Complete App-1, Iku-3 & Iku-6 14.0 14.0Drill & Complete Dev-1, Ewinti 2.1 14.0 9.0 5.0Middleton export facilities refurbishm 0.4 0.4Mooring, hoses, floats 0.2 0.2Engineering for refurb of Middleton 0.2 0.1 0.1Refurbish Middleton platform 5.4 2.7 2.7Ekeh MFP wellhead platform 10.0 5.0 5.0Pipelines 9.2 3.2 6.0Gas Re-injection facilities 3.8 1.8 2.0Water Disposal facilities 0.5 0.2 0.3Drill & Complete Dev-2, Iku-3 9.0 9.0Drill & Complete Dev-3, Iku-6 10.0 10.0Drill & Complete Dev-4, Ewinti 2.1 9.0 9.0Well Abandonments (6) 12.5 5.0 7.5Facilities Abandonment 1.6 1.6Capital Maintenence Allowance 25.6 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Capex total, $m Real 132.9 0.5 1.0 20.6 10.0 1.1 13.9 36.0 10.0 0.0 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 6.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9.1Cum capex, $m Real 132.9 0.5 1.5 22.1 32.1 33.2 47.2 83.2 93.2 93.2 94.4 95.5 96.7 97.8 99.0 100.2 101.3 102.5 108.7 109.8 111.0 112.2 113.3 114.5 115.7 116.8 118.0 119.2 120.3 121.5 122.7 123.8 123.8 123.8 123.8 123.8 123.8 123.8 123.8 123.8 132.9Production MMBBLS ReservesApp-1, b/d 2.08 821 820 819 289 854 842 768 543 560 610 621 600 562 521 479 422 392 378 267 76 32 32 16 26 19 7 0 0 0 0 0 0 0 0 0 0Dev-1, b/d 8.09 4984 4985 4982 1758 5147 5422 5214 2635 1107 551 326 203 137 99 1145 2060 1722 1397 216 68 35 25 20 17 14 9 18 11 7 5 3 2 2 2 2 2Dev-2, b/d 7.97 0 0 0 1039 2675 2493 2324 1655 1788 2078 2176 2133 1995 1823 1771 1532 1352 1141 1060 1049 1065 1042 1004 961 918 878 908 877 844 814 781 750 723 700 677 659Dev-3, b/d 3.21 0 0 0 0 539 1136 1130 1076 1076 1074 1072 1070 1067 1064 1061 1057 1047 1059 961 777 366 220 148 107 80 56 99 62 46 36 25 19 15 14 11 12Dev-4, b/d 3.77 0 0 0 0 2637 5422 5214 2635 1107 551 326 203 137 99 144 68 45 45 45 101 208 218 202 178 153 126 169 141 115 95 74 58 46 39 32 30Total, b/d 25.118 0 0 0 5804 5805 5801 3086 11852 15313 14649 8545 5638 4865 4522 4208 3898 3606 4600 5139 4557 4019 2549 2071 1706 1538 1390 1289 1184 1077 1194 1091 1013 950 883 830 785 754 723 703OpexLease of EPF, 6 months 19.6 6.5 6.5 6.5Lease of Storage Vessel, 6 months 6.0 2.0 2.0 2.0Export Facilities, 6 months 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Support Vessel, JTF, 6 months 59.3 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Supply Vessel, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Crew Boat, 6 months 8.4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Fuel & Lubricants, 6 months 25.3 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7Water, 6 months 5.6 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Feeding & berths, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Pilotage & Clearance, 6 months 9.8 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3Offtake Vessel, 6 months 33.7 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9Production Facilities Maint, 6 months 4.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1Pipelines Maint, 6 months 1.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Wellhead Platform Maint, 6 months 5.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Total 0.0 0.0 0.0 13.5 13.5 13.5 4.9 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3


Table 8-3 Base Case 4 – 5 well development CAPEX and OPEX Forecast



Year Total, $m 2011 2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019 2019 2020 2020 2021 2021 2022 2022 2023 2023 2024 2024 2025 2025 2026 2026 2027 2027 2028 2028 2029 2029 2030 2030 2031Capex H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2 H1 H2

G&A, onshore project team 7.5 0.5 1.0 1.0 1.0 1.0 1.0 1.0 1.0Drill & Complete App-1, & sidetrack 22.0 14.0 8.0Drill & Complete Dev-1, Ewinti 2.1 14.0 9.0 5.0Middleton export facilities refurbishment 0.4 0.4Mooring, hoses, floats 0.2 0.2Engineering for refurb of Middleton 0.2 0.1 0.1Refurbish Middleton platform 5.4 2.7 2.7Ekeh MFP wellhead platform 10.0 5.0 5.0Pipelines 9.2 3.2 6.0Gas Re-injection facilities 3.8 1.8 2.0Water Disposal facilities 0.5 0.2 0.3Drill & Complete Dev-2, Iku-3 9.0 9.0Drill & Complete Dev-3, Iku-6 10.0 10.0Drill & Complete Dev-4 9.0 9.0Drill & Complete Dev-5 9.0 9.0Well Abandonments (7) 14.0 5.0 9.0Facilities Abandonment 1.6 1.6Capital Maintenence Allowance 28.1 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3

Capex total, $m Real 153.9 0.5 1.0 20.6 10.0 1.1 13.9 36.0 10.0 9.0 1.3 9.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 6.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 10.6Cum capex, $m Real 153.9 0.5 1.5 22.1 32.1 33.2 47.2 83.2 93.2 102.2 103.5 112.7 114.0 115.3 116.6 117.9 119.1 120.4 121.7 123.0 124.2 130.5 131.8 133.1 134.4 135.6 136.9 138.2 139.5 140.7 142.0 143.3 143.3 143.3 143.3 143.3 143.3 143.3 143.3 143.3 153.9Production MMBBLS ReservesApp-1, b/d 5.52 1258 1253 1248 415 1241 1003 903 977 303 1876 2024 1847 1643 1426 1262 1129 1018 880 766 669 562 383 415 474 469 474 519 489 472 456 440 418 404 395 380 366Dev-1, b/d 9.49 5081 5083 5081 1794 4934 4840 5121 4760 2489 1074 602 388 275 204 159 126 84 2204 1981 1786 1658 1341 450 204 111 89 39 26 15 7 2 0 0 0 1 1Dev-2, b/d 7.18 0 0 0 1061 2777 2332 2228 1923 1845 1797 1822 1812 1750 1660 1567 1470 1378 1224 1089 968 827 575 625 712 705 713 774 730 706 682 658 624 602 587 563 540Dev-3, b/d 3.87 0 0 0 0 917 1095 1016 935 1098 1099 1098 1097 1096 1094 1092 1089 1087 1090 1093 1087 1282 1034 631 372 230 180 12 72 70 60 53 35 39 31 25 20Dev-4, b/d 4.54 0 0 0 0 2689 5336 5114 4738 2489 1074 602 388 275 204 159 126 118 56 39 20 0 0 0 26 100 134 205 167 153 139 125 99 90 84 70 58Dev-5, b/d 3.35 0 0 0 0 0 0 183 1097 1098 1099 1099 1098 1097 1096 1095 1093 1092 1097 1109 1112 1223 1104 778 454 181 83 44 0 0 0 0 0 0 0 0 0

Total, b/d 33.950 0 0 0 6338 6336 6329 3270 12558 14606 14566 14430 9322 8020 7246 6630 6134 5684 5334 5034 4776 6550 6078 5642 5552 4437 2899 2241 1796 1673 1594 1483 1415 1343 1277 1177 1136 1097 1038 986

OpexLease of EPF, 6 months 19.6 6.5 6.5 6.5Lease of Storage Vessel, 6 months 6.0 2.0 2.0 2.0Export Facilities, 6 months 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Support Vessel, JTF, 6 months 59.3 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Supply Vessel, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Crew Boat, 6 months 8.4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Fuel & Lubricants, 6 months 25.3 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7Water, 6 months 5.6 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Feeding & berths, 6 months 16.8 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Pilotage & Clearance, 6 months 9.8 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3Offtake Vessel, 6 months 33.7 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9Production Facilities Maint, 6 months 4.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1Pipelines Maint, 6 months 1.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Wellhead Platform Maint, 6 months 5.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

Total 0.0 0.0 0.0 13.5 13.5 13.5 4.9 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3


Table 8-4 High Case 12 – 6 well development CAPEX and OPEX Forecast



9. Economics & Commercial

9.1. Marginal Fields Fiscal Terms

The Ekeh Field was awarded to Movido under the Marginal Fields Allocation Round where the fiscal terms were designed to incentivise indigenous companies and encourage the development of small discoveries which were either not economically viable under the older concession agreements or had not been developed because they were too small for the concession holders who, in general, were supermajors. Up to a 40% legal interest in a Marginal Field can be held by a foreign company which enjoys the same fiscal advantages.

9.1.1. Production Royalties

Royalties are payable to the Government on revenue (less handling, treating and storage costs) depending on production rates. In addition, there are overriding royalties paid to the original Licence holder (Chevron and the Nigerian National Petroleum Corporation in the case of OML 88) pursuant to a Farm-out Agreement by way of compensation. There is also a 1% Sustainable Community Development royalty payable to local government.

Oil Production Royalty Oil Production Rate (bpd) OML 88 Licence Holder Nigerian Government

0 - 2000 2.5% 2.5% 2,001 - 5000 3.0% 2.5%

5,001 – 10,000 5.5% 7.5% 10,001 – 15,000 7.5% 12.5% 15,001 – 25,000 7.5% 18.5%

Table 9-1 Royalty Rates

9.1.2. Petroleum Profits Tax (“PPT”)

PPT is payable at a rate of 55% on Profits (Revenue – Royalty – Opex – CAPEX Depreciation). CAPEX is depreciated straight line over 5 years (@20% per year). Deduction of interest on (especially foreign) loans requires Ministry of Finance prior-approval. PPT losses can be carried forward indefinitely.

9.1.3. Investment Tax Credit (“ITC”)

Investment Tax Credit is an uplift on CAPEX to provide a notional allowance for the cost of capital. It is understood (but unconfirmed) that up to 20% ITC is allowed on CAPEX for Marginal Fields. In the case of Ekeh in shallow water, ITC is assumed to be 10%.

Investment Tax Credit Rate %

Onshore Oil 5

Offshore Up to 100 m 10

101 – 200 m 15

> 200 m 20

Upstream Gas (on and offshore) 20

Table 9-2 Investment Tax Credit Rates



Indirect Taxes apply to all Oil Projects but upstream Gas Projects are exempt.

9.1.4. Import Taxes

Import duties vary but average 20%. Port Development Fee is levied at 6% and Port Inspection fee is levied at 1% on the value of goods imported.

9.1.5. Value added Tax (“VAT”)

VAT at 5% is levied on all capital and operating costs. VAT is not usually re-captured as oil exports are zero rated. However, VAT on OPEX is deductible for PPT, and VAT on Depreciated CAPEX is allowable as per CAPEX allowances for PPT.

9.1.6. Niger Delta Development Levy (“NDDC”)

NDDC is levied at 3% on all CAPEX & OPEX.

9.1.7. Education Tax (“ET”)

ET is levied at 2% on Assessable Profit (“AP”) where:

AP = Revenue – Royalties – Opex (but not Capital Allowances)

ET is deductible for PPT

9.2. Commercial Agreements

MRI and Ekeh partners must complete several key commercial agreements before the Ekeh development can proceed.

9.2.1. MRI Farm-in Agreements to Ekeh

MRI has proposed to acquire a 40% interest in the Ekeh Marginal Field development in return for a total funding commitment of $189.5 million comprising a loan of up to $100 million to defray field development costs, assumption of existing joint venture loans of $53 million, and an acquisition premium payable partly in cash upfront and partly from production. The terms of this agreement are agreed in principle but are not legally binding unless and until definitive legal agreements, now under advanced negotiation, are concluded.

9.2.2. Chevron Farm-in Agreement to OML-88.

Ekeh partners signed a Farm-out Agreement with OML 88 partners Chevron and NNPC to develop Ekeh Field under Marginal Field terms. The farm-out agreement includes overriding royalty payments to OML 88 licence holders as described in section 1.1. This agreement expired in 2009 and needs to be novated following the 4 year extension to the initial 5 year Licence term.

9.2.3. Middleton Production Platform Lease and Profit Share Agreement

Movido signed an agreement with the OML 88 operator to lease the Middleton Production Platform as described in section 1.1. This agreement will need to be novated also to extend it coincident with the 4 year extention to the Licence term. A base-line engineering survey inspection is planned prior to signing of definitive agreements. It is expected to confirm the need for major refurbishment to return it to a usable condition.

9.2.4. Pennington Terminal Oil Sales Agreement

It is assumed oil will be sold to Chevron at a sales point at the Pennington Terminal Free on Board at market prices, as was previously envisaged.



9.3. Project Economics

Economic analysis performed on the illustrative cost models shown in Table 8-1 to Table 8-4 at a range of reference oil prices show the Ekeh development to be economically robust.

Figure 9-1 JV NPV10 vs Recoverable volumes

Figure 9-2 JV NPV10 vs Oil Price



9.3.1. Minimum Case 1 – 3 well development

In the minimum case, it is viable to develop the Ekeh field under the technical and contractual assumptions described above at reference prices above $60/b. The field would produce economically up to about 2022 at $100/b reference price, but the low production rates would be uneconomic thereafter. The positive economics, even in the minimum case scenario demonstrate that this is an attractive project to pursue, provided the use of the Middleton Production Platform is technically and contractually feasible.

Oil Price JV Cash Flow MRI Cash Flow JV NPV10 MRI NPV10

$60/b 30.4 8.9 13.8 1.5

$80/b 72.2 31.2 75.0 27.7

$100/b 175.2 73.6 136.2 53.8

$120/b 275.6 113.9 196.5 78.9

Table 9-3 Minimum Case NPV10 and Cashflow Summary

Figure 9-3 Minimum Case JV Net Cash Flow at $100/b



9.3.2. Low Case 5 – 4 well development

In the low case, it is viable to develop the Ekeh field under the technical and contractual assumptions described above. The field would produce economically up to about 2029 at $100/b reference price.


$60/b 153.0 69.3 80.5 30.5

$80/b 308.2 132.5 163.0 65.4

$100/b 463.1 194.2 245.1 99.5

$120/b 613.1 253.5 326.3 132.5

Table 9-4 Low Case NPV10 and Cashflow Summary

Figure 9-4 JV Net Cash Flow at $100/b



9.3.3. Base Case 4 – 5 well development

The base case economics are very attractive, with a break-even point around $40/b, provided the Middleton Production Platform facilities are available to develop the field in the manner described. If it is not available, alternative options such as a standalone platform or FPSO would need to be considered.


$60/b 235.4 100.6 127.9 49.7

$80/b 422.6 178.0 231.0 93.3

$100/b 619.3 256.5 335.1 136.1

$120/b 810.3 332.5 438.1 177.7

Table 9-5 Base Case NPV10 and Cashflow Summary

Figure 9-5 JV Base Case Net Cash Flow at $100/b



9.3.4. High Case 12 – 6 well development

In the high case, cash flow is still positive at end 2030, and the project has positive NPV10 above $32/b. Recoverable volumes would be sufficient for a standalone development.


$60/b 400.2 170.2 197.4 79.3

$80/b 660.8 273.6 328.7 113.3

$100/b 913.8 373.9 458.7 186.1

$120/b 1166.5 474.8 588.6 238.4

Table 9-6 High Case NPV10 and Cashflow Summary

Figure 9-6 High Case JV Net Cash Flow at $100/b



10. Project Risks and Uncertainty Register Ekeh Project Risk Register Page 1

T E C O P

Risk/Opportunity

Category Title Description of Issue Impact or Consequence Probability of Adverse Outcome

Commercial Impact

Ability to Influence

Mitigation Strategy

C R Commercial

Delay to completion of OML88

Commercial Agreements beyond

2011

It is necessary to renew the OML88 farm‐out

agreement and Middleton Platform Lease Agreements

before any significant investments can be made

Project schedule delay H H M Ekeh farm‐in Agreement is conditional upon the

completion of these agreements by Movido

C R CommercialProject schedule dates for

Middleton first oil

Complete upgrade of facil ity and install and

commission Middleton and Ekeh platforms for first

oil Nov 2015

Slippage of project schedule effecting project NPV H M M

E R CommercialProject schedule dates for EPS

first oil

Complete all commercial agreements, progress

technical work to drill wells and deliver first oil to

EPS by Jan 2013

Slippage of project schedule effecting project NPV H L MEnsure all commercial agreements in place and work on

well proposals underway in 2011. EPS facil ity should be

identified and contracted early 2013.

C R Commercial

Change in terms of OML88

Commercial Agreements from

those specified in 2004

Due to changed macro‐economic and fiscal

environment Chevron/NNPC may demand re‐

negotiated terms

Possible increased Royalty, lease or tariff costs M L MEkeh farm‐in Agreement is conditional upon the

completion of these agreements by Movido

O RDevelopment

Dril l ingStuck pipe and hole problems

Poor wellbore condition leading to stuck pipe and

difficulty in running casing.

Poor wellbore would expose the risk of stuck pipe and

casing stickup. Potential to lose the well or need for a

sidetrack

M H HAttention to correct drill ing practices and use of oil based

mud to ensure smooth wellbore and eliminate hole

problems.

T RDevelopment

Dril l ing

Well bore trajectory effects on

success of running completions

and tubulars.

Difficulty running completions and casing due to

wellbore trajectory

Wellbore is drillable to target but the trajectory of the

wellbore is such that the completion and tubing cannot be

run due inclination

L H HEstablish during wellplaning that tubulars, casing and

completion can be run in the proposed well trajectory

prior to drill ing the well

T RDevelopment

Dril l ing

Optimal well placement relating

to faults

Targeting small fault blocks rel ies on precise

knowledge of fault locations

Development /appraisal well drilled on wrong side of

fault or low on structure leaving attic oil in (especially in

NW area)

L H MEnsure sufficient offset from faults. Ensure target windows

tight for directional work.

T RDevelopment

Dril l ingSand production

Poorly designed sand control leading to well

impairment or sand production

Plugging of screens can lead to well impairment and skin.

Sand production can lead to plugging downhole or

erosion of downhole and surface equipment.

H M HAcquire core sample from App‐1 or Dev‐1 to allow grain

size analysis and design of optimum sand control strategy

and completion

O RDevelopment

Dril l ing

Uncontrolled discharge of Oil

Based MudOil based mud discharge to the environment Damage to the environment and potential fine L M H

Ensure correct procedures and effective supervision from

mud company is in place whilst dril l ing oil based mud

section of the well.

O RDevelopment

Dril l ing

Delay to operations in disposal of

oil based mud cuttings

Removing of oil based cuttings by skip to boats,

delayed by weather or insufficient skips to store

cuttings

Drill ing will stop as cuttings volume could not be stored

and removed.M L H

Ensure enough skips are available and have a dedicated

vessel to remove fi l led skips etc

O RDevelopment

Dril l ing

Multiple failure of Mwd and

rotary steerable drill ing tools

Failure of MWD and rotary steerable drill ing tools

due to mechanical failure would have an impact on

drill ing progress

This would lengthen dril l ing time and also leave the

wellbore open longer risking hole problems. Also increase

well cost due to longer drill ing time.

L L MEnsure backup tools are available to cover any tool

failures

T R Drill ing Ekeh‐2H abandonmentAbandonment of Ekeh‐2H compromised by current

mechanical condition.

Specialist equipment required for abandonment, potential

CAPEX overruns and in worst case scenario environmental

complexities

M L HPrepare an abandonment plan for Ekeh‐2H early in the

development program and commit sufficient funds to

allow for any contingency.

CategoriesT = TechnicalE = EconomicC = CommercialO = OperationalP = Political



Ekeh Project Risk Register Page 2T E C O P

Risk/Opportunity


Commercial Impact


Mitigation Strategy

C RFacilities &

Process

Middleton Platform not available

for Processing and evacuation

Current FDP assumes Middleton Platform can be used

for processing and export of oil. If inspection shows

mechanical condition does not justify re‐furb costs

Change of Development Concept to standalone facil ity,

Increased CAPEXL H L

Investigate condition and availability as much as possible

before completing farm‐in agreement, plan for full

inspection before FDP approval.

C RFacilities &

Process

Structural capacity of Middleton

platform to accommodate new

infrastructure (compression etc...)

Limited deckspace or strength of jacket to

accommodate gas compression or other new

facil ities

Additional CAPEX to provide deckspace. Alternately,

change of Development Concept to standalone faci l ity,

Increased CAPEX

M H MInvestigate condition and availability as much as possible

before completing farm‐in agreement, plan for full

inspection before FDP approval.

T RFacilities &

Process

Use of Middleton wells for gas

injection

Current FDP assumes that an abandoned Middleton

well can be used for gas disposal into on of the

depleted field reservoirs. Inspection shows no

suitable well.

Requirement for additional gas disposal well, either in

Ekeh or Middleton and tie in to compression facil ities.

Increased CAPEX

M M LInvestigate condition and availability as much as possible

before completing farm‐in agreement, plan for intervention

during initial dril l ing campaign

T R G & G Ekeh‐1 deviationBottom hole location of Ekeh‐1 uncertain due to

incomplete deviation survey

Affects structural interpretation of field. Ekeh‐1 could be

in separate compartment thus explaining differing oil

samples acquired on Ekeh‐1 and Ekeh‐2H well tests.

L H L Update structural interpretation with new well data

T R G & G Lateral sand connectivity

Two field wells to date penetrate all three major

horizons in close proximity. Sand development away

from well control uncertain.

Potentially lower connected volumes per well. More wells

required to achieve target RFs. Sand connectivity to the

NW is a larger uncertainty than within the SW area

M H L Update structural interpretation with new well data

T R G & G STOIIP Field extents Presence of oil unproven in northwest part of field

If NW wet, STIOIIP close to P90. Minimum case

development, reduction in UR from P50 and impact on

project value

M H L Test with early appraisal well

T R G & G STOIIP Ewinti OWC'sOWC's in Ewinti reservoirs not penetrated by well.

P50 case is calculated on OWC 60' below ODT

New data shows actual OWC close to Ewinti ODT. STOIIP

becomes P90. M H L Test with early appraisal well

C R PermittingConsent to flare for extended

period during EPS phase

Consent is required to flare gas during EPF stage.

Midway hope to receive permission to flare for up to

18 months

Lack of/limited consent will require production shut in for

extended period deferring revenues and reservoir data

acquisition.

H H MGain flaring consents at earl iest possible stage, ideally

before commitment of expenditure

C R Project CAPEX Increased development CAPEX

Project CAPEX higher then forecast due to increased

refurbishment scope in Middleton and/or additional

development well requirement

Impact on project FCF and other economic indicators M M MEarly faci l ities inspection of Middleton required.

Appraisal well and EPS to determine field reserves and

finalise field development plan

T R Res EngFluid PVT property uncertainty in

Ewinti 2.1 & Iku‐6

No sample (surface or downhole) is available for Iku‐

6. A surface sample is available for Ewinti 2.1; but no

laboratory analysis to establish fluid PVT. Two

surface samples for Ewinti 2.1 give widely varying

dead oil sample.

A more viscous crude will result in a lower PI. Where

drawdown constraint is critical in an oil rim

development, this will result in lower achievable well

offtake rates and lower peak field rates for the same well

count.

M H H

Acquire PVT samples for lab measurement from App‐1 or

Dev‐1 well. This will allow achievable well rates for the

development wells on drawdown constraint to be

determined. If required, longer horizontal sections could

be dri lled for more viscous crude

O R Res EngWells coning gas in Iku‐6 with

high drawdown

Production wells produced without drawdown

monitoring and control in oil rims can prematurely

come gas

Gas coning would lead to preferential gas production due

to rel‐perm and lower recovery per wellH H M

Ensure all well have downhole real‐time pressure gauges

to monitor drawdown. Acquire regular reservoir pressure

measurements so ∆p can be assessed. In later field

development l ife, consider completions with drawdown

profile control in the horizontal section




Ekeh Project Risk Register Page 3T E C O P

Risk/Opportunity


Commercial Impact


Mitigation Strategy

O R Res EngWells coning gas in Ewinti 2.1

with high drawdown

Production wells produced without drawdown

monitoring and control in oil rims can prematurely

come gas

Gas coning would lead to preferential gas production due

to rel‐perm and lower recovery per wellM H H

Ensure all well have downhole real‐time pressure gauges

to monitor drawdown. Acquire regular reservoir pressure

measurements so ∆p can be assessed. In later field

development l ife, consider completions with drawdown

profile control in the horizontal section

T R Res EngPosition of Ewinti 2.1 horizontal

well at optimum datum

Unknown OWC within Ewinti 2.1 reservoir leads to

non optimum horizontal placement of well within oil

column of Dev‐1

Well drilled too close to OWC or GOC leading to

premature coning and lower well UR than could be

achieved with optimal placement

M H M

Knowledge gained from App‐1 well may give information

on OWC. If reservoir not present in NW then consider pilot

hole in the Dev‐1 well (provided pilot can be drilled and

main horizontal target stil l landed)

T R Res EngReservoir pressure uncertainty in

Ewinti 2.1 and Iku‐6

Reservoir pressure is anticipated to be normal based

on Iku‐6 MDT; however this must be confirmed

Lower RF would be achieved for an underpressured

reservoirL M H

Acquire pressure sample points on MDT from App‐1 or Dev‐

1 well.

T R Res EngUncertainty in absolute

permeability

No well test data is available to determine kh. No core

is available to determine permeability.

Lower permeabil ity than assumed as base case in the

forecasts will lead to a lower well PI. However, even at

lower permeability, well productivity will stil l be good.

L M HAcquire core for all three main reservoirs in App‐1

(geometry of Dev‐1 not suitable for core acquisition)

T R Res Eng Uncertainty in rel‐perm

Special core analysis is required to estimate water

saturation and relative permeability values for each

fluid.

Change in end‐point assumptions can alter predicted RFs. L M HAcquire core for all three main reservoirs in App‐1

(geometry of Dev‐1 not suitable for core acquisition)




11. Conclusions

The evaluation described above demonstrates that sufficient resources are present in the Ekeh Field to present a potentially economically attractive field development opportunity for MRI. The field can be produced early via an EPS as envisaged by MRI; but does however require further appraisal before a development plan can be optimised. The EPS will provide the necessary appraisal data to lead into a full field development as proposed.

Our analysis demonstrates the presence of 55 to 110 MMstb STOIIP, with technically recoverable resources of 12.31 to 33.95 MMstb, under a range of development scenarios from 3 to 6 wells.

For MRI to be able to realise value from this opportunity the following milestones must be achieved:

Completion of key commercial contracts:

Acquisition agreements to become a partner in the Ekeh Marginal Field,

Novation of the OML88 - Marginal Field Farm-out Agreement with Chevron/NNPC, which is considered a formality following the Nigerian Government’s recent extension of the Licence by 4 years

Novation of the Middleton Production Platform Lease Agreement,

Agreement to use Middleton Field for gas injection and gas supply,

Oil Export and Sales Agreement

Verification of the condition and usability of the Middleton Facilities including:

Platform structural integrity, and ability to accommodate additional facilities such as gas compressors,

Processing facilities condition and usability,

Middleton well condition, integrity and availability for gas injection,

Oil export pipeline conditions and usability,

Verification of Reservoir parameters through further appraisal including:

Appraisal to test the extent of hydrocarbons to the NW and to demonstrate the OWC in the Ewinti-2.1. Define PVT properties for the Iku-6 and Ewinti 2.1 reservoirs,

Long term production testing to confirm well productivity and connected STOIIP volumes,

Coring and fluid sampling to confirm reservoir and fluid properties.

The cost models used for economic analysis assume some cost for platform refurbishment and use, but these issues need to be verified by the planned platform inspection. If the Middleton Production Platform and facilities are not available/usable, a different development plan with different standalone facilities, and possibly higher costs would need to be considered.



12. Abbreviations Used

AOFP Absolute Open Flow Potential AVO Amplitude versus Offset bpd barrels per day bfpd barrels fluid per day bopd barrels oil per day CAPEX Capital Expenditure CHGP Cased Hole Gravel Pack EPS Early Production Scheme EPS Early Production System FPSO Floating Production Storage and Offloading Ft feet FVF Formation Volume Factor FWHP Flowing Well Head Pressure GDT Gas down to GIIP Gas Initially in Place GOC Gas-Oil contact GOR Gas-Oil ratio GRV Gross rock volume GUT Gas up to IPR Inflow Performance Relationship Kh horizontal permeability Kv vertical permeability LAS Log Ascii Standard (digital well log files) LWD Logging While Drilling MD Measured Depth MDT Modular formation Dynamics Tester mD millidarcy (permeability) MMstb million barrels of oil MMscf million standard cubic feet MRI Midway Resources International NMR Nuclear Magnetic Resonance NTU Nephelometric Turbidity Units (particle density in liquid) OBM Oil Based Mud ODT Oil down to OML Oil Mining Licence OPEX Operating Expenditure OUT Oil up to OWC Oil-Water contact PHIE Effective Porosity PHIT Total Porosity Psi pounds per square inch Psia pounds per square inch absolute (pressure relative to a vacuum) Psig pounds per square inch gauge (pressure relative to atmosphere) RMS Root mean squared STOIIP Stock Tank Oil Initially in Place Sw Saturation water



TD Total Depth TVDSS True Vertical Depth sub sea TWT Two Way Time VLP Vertical Lift Performance WBM Water Based Mud W/C Water Cut

Documents

Ekeh Field Competent Person’s Report for Midway … · Competent Person’s Report for Midway Resources International By AGR TRACS ... made to give effect to the original Marginal