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PE 4590 - FS 2019 Final Economics Project -Offshore Field Development- West Africa

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PE 4590 - FS 2019 Final Economics Project -Offshore Field Development- West Africa

PE 4590 – FS 2019

Final Economics Project -Offshore Field Development- West Africa


Your company has entered into a production sharing agreement (PSA) in the blocks #10 and #24 immediately adjacent to Angola, West Africa, March 2018. The agreement expire in the year 2022 if there is no commercial production demonstrated or planned by that time, but will cover a period of 20 years from the time any development plans are agreed. Figure 1 shows the locations of blocks 10 and 24.


Figure 1.  Location of Lease Blocks Offshore Angloa


An exploratory, vertical well was drilled in Block #10 during November, 2018. This well tested with an AOF of 2500 STB/day from approximately 180 ft of net pay in the Pliocene in the main structure. A subsequent vertical well was drilled west in the main structure but in Block 24, proving the northern portion of the main structure as productive. However, seismic indicates there could be a downthrown fault across the field (shown with the dotted line).  There is a 60% of this faulting and if this exists, then wells drilled on the downthrown side will be wet and will not be oil productive.  


Two smaller structures can be seen on seismic, but haven’t yet been drilled.  It is estimated there is a 50% chance of these wells also being productive in the Pliocene.


Water depths vary from 500 ft in the eastern portion of block #10 to slightly over 2000 ft in the western portions of Block #24. The average water depth at the initial drillsite for the first exploratory well was 650 ft.


It is estimated that each well will produce with an initial rate of 2400 bopd, declining at 7% per year. The abandonment rate for each well is expected to be 50 bopd. Each well will drain an area of approximately 1 sq mile. The oil produced from the field is light (31 deg API). The oil has a low producing GOR of 500 scf/stb. This GOR is expected to remain relatively constant. You must provide a use for the gas or re-inject it into the reservoir. (No flaring is allowed now offshore Angloa.)


Angola is an area of high activity and you should consider that as you formulate your development plan.


There is currently only one refinery in Angola – the Luanda Refinery with a capacity of ~65,000 bopd. ENI promoted an international public tender and awarded a contract to expand the gasoline processing capacity of this refinery. A second national refinery project is, planned for the city of Lobito, is currently on hold but will likely be constructed in 2 more years.  Google the location of Luanda refiner, the city of Logito and use the scale on Figure 1 to estimate how far this refinery and the site of the proposed refinery are from your leaseblocks.


You may use any resources and appropriate assumptions that you like to complete this project, but all resources should be copied, attached and correctly cited.  For an oil price, you should start with current oil prices and use the World Bank average crude oil projection (Figure 2):



Figure 2.  World Bank Average Crude Oil Price Projections found at






  1. Define the key financial terms (cost recovery, tax, royalty, etc) of the production sharing contract you negotiated with Angola for this project.


  1. Determine the risk weighted reserves associated with these structures.


  1. Assume the small structure in Block 10 is successful, there is no fault in the main structure, but the small structure to the north is dry. Develop a field development plan for the two productive structures. 


Some key things to decide:  If each well drains 1 sq mile, how many wells are required?  How much drilling time?  What type of main production facility will you use?  How far can a directional well reach from that main facility?  Do you need more than one production facility to drain the structure?  What is the timing for all facilities/drilling etc?  How will you transport your oil to shore and process it?


Note: If you are drilling many wells from a single production facility you will likely use many deviated wells. KOP should be 2000 ft, and the maximum deviation is 60deg. Buildup rate = l deg/100 ft.  Pliocene reservoir depth averages 8000 ft (below mud line). Assume a common KOP for all wells and then find the maximum lateral reach given this drilling plan.  You can choose to use satellite subsea templates and vertical wells also.


  1. Make a copy of the structure map and show the locations of main production facilities, well reach from those facilities (for any deviated wells) and the locations of all wells (including future injection wells).


  1. Determine the project schedule showing timing for all capital expenses, drilling costs, etc. Show costs on an annual basis.  Prepare a Gantt chart of the major tasks and show their timing by year.  Engineering design for the project should begin in January, 2019.   Allocation of annual capital and operating expenses much match the activities shown on the Gantt chart.


  1. Develop a cash flow for the project using the terms of your PSA for 20 years.


  1. What is the net present value of this project for your company?


  1. Prepare an Executive Summary of the work which details any assumptions made in the evaluation. Attach any references used (not required but if you found information from a source, then cite that source in your Executive Summary).    Prepare a cover letter for the project which gives a 1 paragraph summary of the findings, costs, any key economic indicators you feel are important and a recommendation of whether to sign the PSA.










Expected Development Times for Various Project Tasks



TASK                                                                          DURATION


Preliminary engineering studies                                               3 months

Contractors bids and bid award                                               1 month

Detailed engineering studies                                        5 months


Platform drilling and completion                                 2 months/well

Subsea drilling and completion                                                2.5 months/well


Steel jacket design and fabrication (up to 1000 ft water)         12 months

Steel jacket design and fabrication (over 1000 ft water)          15 months

Subsea template design and fabrication                                   9 months


Steel jacket installation            and commissioning                  0.5 month

Template installation and commissioning                    0.25 month


In-field subsea flowline fabrication/install                   3 weeks/mile

Pipeline to shore (oil or gas) fabricate and install                     12 months                                           




Drilling and Production Facilities Costs

Steel jacket & topsides for up to 1000 ft water depth              $75MM

Steel jacket & topsides for over 1000 ft water depth               $125MM                                             


Export pipeline to shore                                                                       $1MM/mile

In-field flowlines and umbilicals                                                         $500M/mile


Platform drilling and completion                                             $20MM/well

Subsea drilling and completion                                                            $25MM/well

Subsea template cost                                                                $20MM

Subsea production manifold                                                    $5MM


Controls package at central facility for subsea wells                $5MM/template OR

                                                                                                $500M for a single subsea well                                                                      


Operating Costs

Annual general operating cost                                                  1% of production facilities CAPEX  (exclude drilling and completion)


Assume every well requires workover once every 6 years      $5MM/well – once every 6 years.




Other Operating Costs

Throughput cost if using another companies export line                      $0.65/stb transported

(You must demonstrate where that line is)


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