Project Evaluation of Oil and Gas Field

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The assignment comprises the production of a field development plan for an oilfield. It is split into two parts, and data for the case study is provided below.

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Assignment Part 2a Economics INSTRUCTIONS FOR USE: 1. FILL IN THE SHADED CELLS WITH RELEVANT INFORMATION. 2. COPY THE ENTIRE WORKSHEET TO A NEW TAB IF YOU WANT TO RUN DIFFERENT CASES. 3. CUT AND PASTE INFORMATION IF YOU NEED TO MOVE IT RATHER THAN MOVE OR DELETE THE CELLS AS THIS WILL ALTER THE CALCULATIONS 4. ENSURE YOU LABEL THE WORKSHEET WITH YOUR SELECTED OPTION AS "FINAL" Discount rate 9 % Total CAPEX 0 £ million inputs Oil price 50 $/bbl NPV 0.0 £ million Oil pipeline tariff 1.2 £/bbl IRR ERROR:#NUM! Gas price 0.5 £/therm Gas tariff 8 £/MMscf Tax rate 20 % OPEX 8 £/bbl liqs Exchange rate 1.5 $/£ Period Year Total liquids Oil export Sales gas (excl fuel gas) Sales gas (excl fuel gas) Oil sales Gas sales Oil tariff Gas tariff OPEX CAPEX Abandonment Cost Cash flow (pre tax) Tax Cash flow (post tax) Discounted cash flow (PV) kbbls/year kbbls/year MMscf/year therm £ million £ million £ million £ million £ million £ million £ million £ million £ million £ million £ million 0 2021 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 1 2022 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 2 2023 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 3 2024 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 4 2025 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 5 2026 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 6 2027 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 7 2028 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 8 2029 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 9 2030 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 10 2031 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 11 2032 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 12 2033 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 13 2034 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 14 2035 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 15 2036 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 16 2037 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 17 2038 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 18 2039 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 19 2040 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 20 2041 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 21 2042 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 22 2043 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 23 2044 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 24 2045 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 25 2046 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 26 2047 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 27 2048 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 28 2049 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 29 2050 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 30 2051 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 31 2052 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 32 2053 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 33 2054 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 34 2055 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 35 2056 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 36 2057 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 37 2058 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 38 2059 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 39 2060 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 40 2061 0.00E+00 0.0 0.0 0.0 0.00 0.0 0.0 0.0 0.0 0.0 Notes for economics Provide Notes Assignment Part 2b Options INSTRUCTIONS FOR USE: 1. Score each option against each of the criteria ensuring that no two Options have the same score for the crieteria being assessed. See below for scoring convention. 2. Add notes against each option and each criteria to summarise the rationale for the scoring. Make sure that options are differentiated. 3. Fill out the section below the main table detailing the final option selection. 4. Provide a summary of the main reasons for your final option selection. Score 0 Least preferred 1 2 3 4 Most preferred Concept Options A Single Steel Jacket B Twin Steel Jackets C Converted Jack-up D FPSO E Subsea Tie-back Comment Score Comment Score Comment Score Comment Score Comment Score Criteria Technical Economic Safety Environmental OVERALL 0 0 0 0 0 FINAL OPTION SELECTION Enter the selected option here -> Summarise the main reasons for selecting this option (200 words maximum)
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PENG 356: Project Evaluation of Oil and Gas Field INSTRUCTIONS The assessment for this module comprises the production of a field development plan for an oilfield. It is split into two parts to be completed in succession over the course of the module. There is an element of individual and group work. Groups will be assigned randomly. All group submissions should have a cover sheet signed by each individual in the group as evidence of your participation and contribution. If your signature is not on the cover sheet, then you will not be assigned any marks. No individual submission in lieu of a group submission will be accepted. Submission will be via Google Classroom (code: 5bgusd3, see schedule). Penalties for late submission will be in accordance with the department’s policy (Student Handbook). Data for the case study is provided here and will be released in two stages as per the schedule below. Please read the assignment brief carefully. SUBMISSION & SCHEDULE ALL assignments should be submitted as a PDF. 1 – Reservoir and Wells Evaluation Available immediately. Submission Deadline is 5 weeks from course start date. 1A Development Opportunity (INDIVIDUAL) 30 Marks 1B Wells Productivity (INDIVIDUAL) 20 Marks 2 – Field Development Plan Available the day after submission of first part of assignment. 2A Option Design, Selection and Evaluation (GROUP) 20 Marks – Process flow diagram for topsides (Group). – Completed Excel Workbook (Group) [Detailed study will be presented in PENG 457] 2B Investment Decision Paper (INDIVIDUAL) 30 Marks 1 PART 1 – RESERVOIR AND WELLS EVALUATION (INDIVIDUAL SUBMISSION, 50 MARKS) 1A Development Opportunity Description (30 marks) Based on the information provided, prepare an initial high-level evaluation of the development setting out the main parameters of the field. The document should be structured with the following sections: • Executive Summary. • Reservoir Fluids. • Hydrocarbon Reserves. • Depletion Plan. • Export Routes. The following should be covered in each section as appropriate: • Summary paragraph providing an overview of the development with pertinent information for decision makers. • Description of the hydrocarbon characteristics at reservoir conditions, including a representative phase envelope for the fluids. • Characterisation of the oil at stock tank conditions. • Estimate of the hydrocarbon reserves initially in place. • Estimated recovery factor based on the preliminary production profile provided. • Qualitative evaluation of the potential depletion plan options, including enhanced oil recovery. • Qualitative evaluation of the potential export routes. PAGE LIMIT = 2 sides A4, Font 11 (excluding appendices which MUST include supporting calculations) 1B Wells Productivity (20 Marks) Data from a well test is provided along with a proposed production well design. Using this data and assuming semi steady-state incompressible flow: 1. Determine the average well productivity index for a production well. 2. Construct a well inflow performance curve for a production well which should include the absolute open flow oil rate. 2 3. Estimate the number of wells required to achieve the peak production rate shown in the production profile. Assume that the drawdown is limited to 1000 psi for production. PAGE LIMIT = 2 sides A4, Font 11 with answers to questions 1 – 3 (excluding appendices with supporting calculations) 3 PART 2 - FIELD DEVELOPMENT PLAN (INDIVIDUAL SUBMISSION, 50 MARKS) Ensure you submit a PFD and completed workbook for 2A 2A OPTION DESIGN, SELECTION AND EVALUATION (GROUP SUBMISSION, 20 MARKS) The Group task is to work together to evaluate each of the Options (A, B, C, D, E) and make a final selection. An economic assessment of the development based on the selected option is to be presented along with a topsides process scheme. Work in your assigned Groups to produce the following: • Process Flow Diagram • Economic Assessment • Options Ranking and Final Option Selection Further details on the requirements are set out below. Process Flow Diagram (10 marks) Based on the information provided, propose an oil and gas processing scheme for your selected Option in the form of an annotated block diagram showing key design parameters – pressure, temperature, oil residence time and flow. (There is no need to show duplicate equipment, just indicate this on the block diagram as “x2”). Provide the rationale for the major design decisions. For Options A, B, C, and D your considerations should include issues such as: • Number of separation stages required. • Number of trains. • Processing capacities. • Impact of temperature in separation and the optimum place(s) for heat input. • Recycling of separated water. • Residence times. • Sufficiency of gravity separation alone. • Requirement for gas dehydration. • Number of compression stages (assume 4:1 compression ratio). 4 For Option E the following guidance should be used for developing a process flow scheme: • Read the Scott Ullage profiles document at the website link provided in the Case Study Data. • Seabed temperature = 5°C. • Scott does not have any spare three phase separation capacity. • Scott gas handling system comprises four stages of compression with gas dehydration between the third (HP) and fourth (Export) stage operating at 68 barg. Identify tie-in locations for gas from your development. The compressor suction pressures are as follows: – Low Pressure (LP) = 7.1 barg – Intermediate Pressure (IP) = 12.9 barg – High Pressure (HP) = 20.5 barg – Export = 67 barg • Show the required flowline connections between the subsea wells and the topsides for all the required fluid streams. PAGE LIMIT = PFD should be submitted on a single PowerPoint slide or as a PDF. Explanatory notes of decisions should be limited to a single side of A4, Font 11 (preferably in PDF format). Economic Assessment (5 marks) Use the Excel workbook provided to help with economic screening of the Options. A full economic assessment for your final selected Option must be presented in the Excel workbook provided, including any sensitivity analysis. Use the Notes tab in the workbook to provide a summary of all major assumptions used in the analysis. WORD COUNT LIMIT FOR NOTES = 500 Options Ranking and Final Option Selection (5 marks) Company A screens concepts in the following categories all with equal weightings: technical (25%), economic (25%), safety (25%), and environmental (25%). Using these categories provide an assessment for each Option with appropriate evidence in the Excel workbook provided: • Complete the option ranking in the Excel workbook. Rank each option from 4 (most preferred) to 0 (least preferred) against each of the criteria providing comments as appropriate. • Present a final recommendation for the development supported by a short summary outlining the main reasons for your selection in the allocated box within the Excel workbook (200 words maximum). The Economic Assessment and Options Ranking should be completed and submitted in the Excel Workbook provided. Ensure you provide entries in all the required cells. 5 2B INVESTMENT DECISION PAPER (INDIVIDUAL COMPONENT, 30 MARKS) Write an Investment Decision Paper making your recommendation for which Option Company A should pursue. Your answer should comprise the following sections: 1. Development Plan – summarise the selected Option including export routes for products. 2. Petroleum Reserves – describe the economic recovery of petroleum reserves including total production, life of project and any enhancements which might be considered for improved oil recovery. 3. Financial summary – summarise the total Capital Expenditure, phased spending profile and overall economic performance of the development. 4. Risks – discuss four main risks to the ultimate value of the development and identify mitigations or opportunities for each risk that should be pursued in the next stages of the development. PAGE LIMIT = 2 sides A4, Font 11 (excluding appendices). You should submit 1 file (a PDF document). 6
Degree of BSc in Petroleum Engineering BSc Petroleum Engineering PENG 356 Practical Evaluation of Oil and Gas Field CASE STUDY DATA – PART 1 Acronyms & Abbreviations STOIIP Stock tank oil initially in place API American Petroleum Institute FPSO Floating Production Storage & Offloading BS&W Base Sediment & Water TEG Tri-ethylene glycol RVP Reid Vapour Pressure NPV Net present value CAPEX Capital Expenditure IRR Internal rate of return OPEX Operating Expenditure GOR Gas oil ratio ST Stock tank mbd thousand barrels per day MMscfd Million standard cubic feet per day STB stock tank barrels scf standard cubic feet g/cc grams per cubic centimetre cf cubic feet bbls barrels therm unit of heat energy Location Buchan Area of the Central North Sea – refer to map provided. Water Depth = 120 m Infrastructure in the Area Information on capacity and entry specifications for infrastructure in proximity to the development can be found at the following links: Flotta Oil Terminal https://www.repsolsinopecuk.com/files/ICOP_Flotta_2017.pdf Forties Pipeline https://www.ineos.com/businesses/ineos-fps/technical/system-ullage/ SAGE Pipeline http://www.ancalamidstream.com/technical/ Scott https://intl.cnoocltd.com/operations/europe/uk Reservoir Characteristics Crude Oil Gravity [°API] 35.8 Cumulative Solution GOR [scf/STB] 395.1 Reservoir Depth [m] 2860 m Initial Pressure at Datum [psia] 4473 Reservoir Temperature [°C] 104.4 Bulk rock volume [m3] 3.38x109 Net to gross ratio 0.823 Average Porosity; φ 10.9% Area [sq km] 14.28 Average water saturation; Sw 0.23 Average permeability [md] 21 Well Sample Analysis Differential Vaporisation @ 104.4°C Pressure Oil Volume Factor Bo GOR Rs Gas Compressibility Gas Formation Volume Factor Bg Gas gravity Liquid density bbls/STB scf/STB Z cf/scf psia g/cc 4473 1.3034 395.1 - - - 0.7417 3749 1.3181 395.1 - - - 0.7334 3499 1.3236 395.1 - - - 0.7304 2999 1.3353 395.1 - - - 0.7239 2949 1.3366 395.1 - - - 0.7233 1846 1.3672 395.1 - - - 0.7071 1610 1.3657 395.1 0.914 0.0109 0.73 0.7062 1465 1.3462 383.9 0.917 0.0120 0.73 0.7121 1320 1.3274 353.7 0.920 0.0134 0.73 0.7178 1175 1.3093 324.2 0.923 0.0151 0.74 0.7234 1030 1.2918 295.5 0.927 0.0173 0.75 0.7289 885 1.2748 267.5 0.932 0.0203 0.76 0.7342 740 1.2582 240.0 0.937 0.0244 0.78 0.7394 595 1.2418 212.9 0.943 0.0305 0.80 0.7445 350 1.2122 186.1 0.954 0.0525 0.89 0.7535 100 1.1655 139.0 0.969 0.1866 1.25 0.7651 15 1.0865 74.6 0.984 1.2888 2.31 0.7784 15 1.0000 - - - - 0.8457 A HYSYS file “CP527_971 case study base data.hsc” is provided with the above differential vaporisation test reconstructed. Oil Properties Wax Wax appearance temperature 35°C. Wax dissolution temperature 60°C. Wax content – 6.2 wt.%. H2S The reservoir is likely to sour quickly if injected with raw untreated seawater. Souring prevention and mitigation measures will therefore be required if pressure support from water injection is to be utilised. The peak H2S production rate has been calculated as 113 kg/d and preliminary modelling shows that this results in a maximum gas phase H2S concentration of <100ppmv if souring mitigations are implemented. Oil/Water Mixture Viscosity Laboratory work has shown that below the inversion point of 55% water cut, the effective viscosity (μ) of the oil/water mixture can be approximated by Taylor’s equation: Where: = ratio of dispersed phase (water) viscosity to continuous phase (oil) μw = water viscosity (cP) μo = oil viscosity (cP) = ratio of effective viscosity to oil viscosity fw = volume fraction of water in oil Above the inversion point the viscosity approximates Well Data The appraisal well for the field flowed on test at the following conditions: Orientation Vertical Length of perforated interval [m] 115 Flow [STB/day] 7635 Bottom hole flowing pressure [psig] 3958.55 Oil viscosity [cP] 0.672 Wellbore inside diameter [in] 3 Estimated drainage extent (radius) [m] 950 It is proposed to use 5” production tubing with an inner diameter of 108.61 mm and producing interval of 150 m per well. Expected flowing wellhead pressure (dry or wet trees) = 40 - 60 barg. Expected flowing wellhead temperature (dry trees) = 70 – 80°C. Expected flowing wellhead temperature (wet trees) = 100°C. Topsides arrival temperature ~ 20°C. Production Profiles Preliminary production profile forecasts are shown below: Year Peak Daily Oil Rate [mbd] Water Cut [%] Peak Daily Gas Lift Rate [MMscfd] Operating Efficiency 1 9.0 0.0 0 50% 2 26.0 0.0 6.3 75% 3 56.0 0.0 10.1 80% 4 56.0 0.0 14.6 90% 5 56.0 1.8 15.3 75% 6 56.0 3.6 16.2 85% 7 56.0 5.4 17 85% 8 56.0 7.2 17.7 85% 9 53.0 9.0 18.5 75% 10 48.4 10.8 17.9 85% 11 44.3 12.6 17.5 85% 12 40.5 14.4 17.2 75% 13 37.0 16.2 17 85% 14 33.8 18.0 16.9 85% 15 30.9 19.8 16.9 78% 16 28.2 21.6 16.6 85% 17 25.8 23.4 16.1 90% 18 23.6 25.2 15.7 80% 19 21.6 27.0 15.3 90% 20 19.7 28.8 15 90% 21 18.0 30.6 14.6 82% 22 16.5 32.4 14.2 90% 23 15.0 34.2 13.8 90% 24 13.7 36.0 13.5 90% 25 12.6 37.8 13.2 90% 26 11.5 39.6 13.2 90% 27 10.5 41.4 13.2 90% 28 9.6 43.2 13.2 90% 29 8.8 45.0 13.2 90% 30 8.0 46.8 13.2 90% 31 7.3 48.6 13.2 90% 32 6.7 50.4 13.2 90% 33 6.1 52.2 13.2 90% 34 5.6 54.0 13.2 90% 35 5.1 55.8 13.2 90% Page of
Degree of BSc in Petroleum Engineering BSc Petroleum Engineering PENG 356 Practical Evaluation of Oil and Gas Field CASE STUDY DATA – PART 2 Acronyms & Abbreviations STOIIP Stock tank oil initially in place API American Petroleum Institute FPSO Floating Production Storage & Offloading BS&W Base Sediment & Water TEG Tri-ethylene glycol RVP Reid Vapour Pressure NPV Net present value CAPEX Capital Expenditure IRR Internal rate of return OPEX Operating Expenditure GOR Gas oil ratio ST Stock tank mbd thousand barrels per day MMscfd Million standard cubic feet per day STB stock tank barrels scf standard cubic feet g/cc grams per cubic centimetre cf cubic feet bbls barrels therm unit of heat energy Location Buchan Area of the Central North Sea – refer to map provided. Water Depth = 120 m Infrastructure in the Area Information on capacity and entry specifications for infrastructure in proximity to the development can be found at the following links: Flotta Oil Terminal https://www.repsolsinopecuk.com/files/ICOP_Flotta_2017.pdf Forties Pipeline https://www.ineos.com/businesses/ineos-fps/technical/system-ullage/ SAGE Pipeline http://www.ancalamidstream.com/technical/ Scott https://intl.cnoocltd.com/operations/europe/uk Reservoir Characteristics Crude Oil Gravity [°API] 35.8 Cumulative Solution GOR [scf/STB] 395.1 Reservoir Depth [m] 2860 m Initial Pressure at Datum [psia] 4473 Reservoir Temperature [°C] 104.4 Bulk rock volume [m3] 3.38x109 Net to gross ratio 0.823 Average Porosity; φ 10.9% Area [sq km] 14.28 Average water saturation; Sw 0.23 Average permeability [md] 21 Well Sample Analysis Differential Vaporisation @ 104.4°C Pressure Oil Volume Factor Bo GOR Rs Gas Compressibility Gas Formation Volume Factor Bg Gas gravity Liquid density bbls/STB scf/STB Z cf/scf psia g/cc 4473 1.3034 395.1 - - - 0.7417 3749 1.3181 395.1 - - - 0.7334 3499 1.3236 395.1 - - - 0.7304 2999 1.3353 395.1 - - - 0.7239 2949 1.3366 395.1 - - - 0.7233 1846 1.3672 395.1 - - - 0.7071 1610 1.3657 395.1 0.914 0.0109 0.73 0.7062 1465 1.3462 383.9 0.917 0.0120 0.73 0.7121 1320 1.3274 353.7 0.920 0.0134 0.73 0.7178 1175 1.3093 324.2 0.923 0.0151 0.74 0.7234 1030 1.2918 295.5 0.927 0.0173 0.75 0.7289 885 1.2748 267.5 0.932 0.0203 0.76 0.7342 740 1.2582 240.0 0.937 0.0244 0.78 0.7394 595 1.2418 212.9 0.943 0.0305 0.80 0.7445 350 1.2122 186.1 0.954 0.0525 0.89 0.7535 100 1.1655 139.0 0.969 0.1866 1.25 0.7651 15 1.0865 74.6 0.984 1.2888 2.31 0.7784 15 1.0000 - - - - 0.8457 A HYSYS file “CP527_971 case study base data.hsc” is provided with the above differential vaporisation test reconstructed. Oil Properties Wax Wax appearance temperature 35°C. Wax dissolution temperature 60°C. Wax content – 6.2 wt.%. H2S The reservoir is likely to sour quickly if injected with raw untreated seawater. Souring prevention and mitigation measures will therefore be required if pressure support from water injection is to be utilised. The peak H2S production rate has been calculated as 113 kg/d and preliminary modelling shows that this results in a maximum gas phase H2S concentration of <100ppmv if souring mitigations are implemented. Oil/Water Mixture Viscosity Laboratory work has shown that below the inversion point of 55% water cut, the effective viscosity (μ) of the oil/water mixture can be approximated by Taylor’s equation: Where: = ratio of dispersed phase (water) viscosity to continuous phase (oil) μw = water viscosity (cP) μo = oil viscosity (cP) = ratio of effective viscosity to oil viscosity fw = volume fraction of water in oil Above the inversion point the viscosity approximates to the water viscosity at the prevailing temperature and pressure. Well Data The appraisal well for the field flowed on test at the following conditions: Orientation Vertical Length of perforated interval [m] 115 Flow [STB/day] 7635 Bottom hole flowing pressure [psig] 3958.55 Oil viscosity [cP] 0.672 Wellbore inside diameter [in] 3 Estimated drainage extent (radius) [m] 950 No skin was observed. It is proposed to use 5” production tubing with an inner diameter of 108.61 mm and producing interval of 150 m per well. Expected flowing wellhead pressure (dry or wet trees) = 40 - 60 barg. Expected flowing wellhead temperature (dry trees) = 70 – 80°C. Expected flowing wellhead temperature (wet trees) = 100°C. Topsides arrival temperature ~ 20°C. Production Profiles Preliminary production profile forecasts are shown below: Year Peak Daily Oil Rate [mbd] Water Cut [%] Peak Daily Gas Lift Rate [MMscfd] Operating Efficiency 1 9.0 0.0 0 50% 2 26.0 0.0 6.3 75% 3 56.0 0.0 10.1 80% 4 56.0 0.0 14.6 90% 5 56.0 1.8 15.3 75% 6 56.0 3.6 16.2 85% 7 56.0 5.4 17 85% 8 56.0 7.2 17.7 85% 9 53.0 9.0 18.5 75% 10 48.4 10.8 17.9 85% 11 44.3 12.6 17.5 85% 12 40.5 14.4 17.2 75% 13 37.0 16.2 17 85% 14 33.8 18.0 16.9 85% 15 30.9 19.8 16.9 78% 16 28.2 21.6 16.6 85% 17 25.8 23.4 16.1 90% 18 23.6 25.2 15.7 80% 19 21.6 27.0 15.3 90% 20 19.7 28.8 15 90% 21 18.0 30.6 14.6 82% 22 16.5 32.4 14.2 90% 23 15.0 34.2 13.8 90% 24 13.7 36.0 13.5 90% 25 12.6 37.8 13.2 90% 26 11.5 39.6 13.2 90% 27 10.5 41.4 13.2 90% 28 9.6 43.2 13.2 90% 29 8.8 45.0 13.2 90% 30 8.0 46.8 13.2 90% 31 7.3 48.6 13.2 90% 32 6.7 50.4 13.2 90% 33 6.1 52.2 13.2 90% 34 5.6 54.0 13.2 90% 35 5.1 55.8 13.2 90% ADDITIONAL DATA FOR PART 2 Production Profile - Update It has been decided to include water injection in the development to maintain the reservoir pressure at 210 bara throughout the field life. The reservoir engineers have provided an updated production profile. The peak daily total well rate expressed in volumetric flow at a reservoir pressure of 210 bara is shown. This rate excludes water. Year Peak Daily Total Well Rate [mbd] Water Cut [%] Peak Daily Gas Lift Rate [MMscfd] Operating Efficiency 1 12.5 0.0 0 50% 2 36.1 0.0 6.3 75% 3 77.8 0.0 10.1 80% 4 77.8 0.0 14.6 90% 5 77.8 2.3 15.3 75% 6 77.8 4.6 16.2 85% 7 77.8 6.9 17 85% 8 77.8 9.1 17.7 85% 9 73.7 11.4 18.5 75% 10 67.3 13.7 17.9 85% 11 61.5 16.0 17.5 85% 12 56.2 18.3 17.2 75% 13 51.4 20.6 17 85% 14 47.0 22.9 16.9 85% 15 42.9 25.1 16.9 78% 16 39.2 27.4 16.6 85% 17 35.9 29.7 16.1 90% 18 32.8 32.0 15.7 80% 19 30.0 34.3 15.3 90% 20 27.4 36.6 15 90% 21 25.0 38.9 14.6 82% 22 22.9 41.1 14.2 90% 23 20.9 43.4 13.8 90% 24 19.1 45.7 13.5 90% 25 17.5 48.0 13.2 90% 26 16.0 50.3 13.2 90% 27 14.6 52.6 13.2 90% 28 13.3 54.9 13.2 90% 29 12.2 57.2 13.2 90% 30 11.1 59.4 13.2 90% 31 10.2 61.7 13.2 90% 32 9.3 64.0 13.2 90% 33 8.5 66.3 13.2 90% 34 7.8 68.6 13.2 90% 35 7.1 70.9 13.2 90% Gas Lift Design Parameters Gas lift pressure required = 240 barg. Maximum allowable temperature = 60°C Gas lift water content = 35 ppm (volume) maximum Separator Design Water droplet size distribution for separator sizing: Droplet Size [microns] Cumulative Volume % 100 10 250 21 450 55 600 85 900 92 1200 100 Separator outlet water-in-oil specification = 5 % by volume. Page of
Degree of BSc in Petroleum Engineering BSc Petroleum Engineering PENG 356 Practical Evaluation of Oil and Gas Field CASE STUDY DATA – PART 3 Acronyms & Abbreviations STOIIP Stock tank oil initially in place API American Petroleum Institute FPSO Floating Production Storage & Offloading BS&W Base Sediment & Water TEG Tri-ethylene glycol RVP Reid Vapour Pressure NPV Net present value CAPEX Capital Expenditure IRR Internal rate of return OPEX Operating Expenditure GOR Gas oil ratio ST Stock tank mbd thousand barrels per day MMscfd Million standard cubic feet per day STB stock tank barrels scf standard cubic feet g/cc grams per cubic centimetre cf cubic feet bbls barrels therm unit of heat energy ECONOMIC DATA Economic Information (use spreadsheet provided) Tariffs - oil pipeline 1.20 £/bbl, gas pipeline 8 £/MMscf Oil price - 50 $/bbl Gas price - 0.50 £/therm (assume 96.6 scf/therm for produced gas) Capital cost (CAPEX) estimating: Item £ million Schedule [months] Steel Jacket - accommodation 97.0 9 Steel Jacket – production and drilling 204.0 12 Topsides- accommodation only 104.0 14 Topsides - production Based on capital cost blocks 20 FPSO – hull and marine systems 184.0 18 Drilling - wet trees (per well) 39.0 2 months per well Drilling - platform, dry trees (per well) 27.0 1 month per well Pipeline (installed cost per km) 1.7 4 km per day Subsea systems (per template) 48.0 Module on host platform (excludes production equipment) 186.0 24 months % of Total Equipment Costs Bulks (valves, pipe, cables) - topsides 70% % of Total Bulk +Equipment Costs Engineering 8% Installation (where not included above) 4% Owners costs 5% Unallocated Provision 7% Capital Cost Blocks for Equipment Items Production separator: $5 million each Production Heat Exchanger: $1.5 million LP compressor (motor driven): $20 million LP compressor (GT driven): $30 million MP/HP compressor (motor driven): $30 million MP/HP compressor (GT driven): $40 million Gas dehydration unit: $14 million Instrument air utilities: $3 million Cooling Water & Utilities: $18 million Flare system: $12 million Power Generation: $45 million Major Pumps (50000 bbls/day capacity - water injection, main oil export etc.): $15 million each Process Pumps (water recycle etc.): $0.7 million each Produced Water Treatment: $12 million Abandonment costs £120 million Operating expenditure (OPEX) = 8 £/bbl total liquids Taxes - 20% profit Discount rate 9% Drilling 10 production wells each with a design oil rate of 12000 bbls/day Three water injection wells with a design water rate of 20000 bbls/day Production Operating efficiency benefit from dual trains is estimated to be 3% overall. Capital Expenditure (CAPEX) Phasing Option First Oil Year CAPEX Phasing by Year [%] 2021 2022 2023 2024 2025 2026 A & B 2025 10 10 25 20 20 15 C 2023 10 25 25 25 10 5 D 2024 10 10 20 25 20 15 E 2023 10 30 30 25 5 - Page of

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