Your company has acquired a 50% interest in offshore oil blocks in Angola, West Africa. Initial exploratory drilling in block 10 found light oil reserves producing 2,500 bbl/day. Additional wells in block 24 further proved the reserves. The blocks contain multiple underwater oil structures that will require development. You must formulate a development plan, selecting from alternatives like fixed platforms, floating production vessels, or subsea wells. Your plan should include well numbers and locations, production forecast, facility design, costs and schedule and economic evaluation to determine the best option.
1. Senior Design Project
Offshore Field Development – West Africa Angola
TECHNICAL DATA
Your company has purchased a 50% interest in the blocks #10 and #24 immediately adjacent to
Angola, West Africa. The blocks were acquired in the bid round in September, 2002. The leases
expire in the year 2015 if there is no proven or potential commercial production demonstrated
at that time.
Block #10 was targeted for an immediate exploratory well, which was drilled in November,
2002. This well produced with an AOF (Absolute Oil Field) of 2500 STB/day from approximately
180 – 360 ft of net pay in the Pliocene. Two subsequent deeper wells were drilled west in
Block #24, proving those reserves. Two other extension wells were found to be dry, but could
be used as injection wells.
Water depths vary from 500 ft in the eastern portion of block #10 to slightly over 6000 ft in the
western portions of Block #24. The average water depth at the initial drill site for the
exploratory well was 550 ft.
Each of the structure shown on the attached maps is based on 3-D seismic. The features are not
named. You should provide a name or designation for each structure.
Based on initial well, it is projected that the average shallow water department oil well will
produce 5000 bopd and that wells in deep water will produce up to 15000 bopd. Well
production rate will be constant for 2 years, with 20%/year constant decline thereafter.
Abandonment is expected in 25-30 years’ time or when reserves are depleted. Reservoir
porosity and perm is 0.25 and 500mD respectively, and each well is projected to drain up to
approximately 1 sq mile. (See attached field data sheet).
Although the reservoir pressure is high, it is expected to decline after the 4th
year of production.
Hence, water injection will need to be added in the 3rd
year of production for the oil fields.
The oil produced from the field is light (31 deg API). The oil has a producing GOR of 600 scf/stb
and this GOR is expected to remain relatively constant.
Angola is an area of high activity (read attached articles) and you should consider that as you
formulate your development plan. You may assume shared facilities or use offshore based
facilities which currently being planned. You must provide a use for the gas or re-inject it into
2. the reservoir. (No flaring is allowed now offshore Angola). You may use any resources that you
like to complete this project, but all resources should be copied, attached and correctly cited.
FORMULATE A DEVELOPMENT SCHEME
Tasks you should complete:
1. Obtain a three ring binder to accumulate and organize your work (TEAM NOTEBOOK).
This binder will be submitted as if you were sending it to management for approval, or
presenting it to a bank to obtain project financing.
2. Make a team of five people, and break down the tasks. You may want to have people
with skills in Drilling, Well Design, Production, Economics, Geo-mechanics and Offshore
Facilities. Vote for a team leader. Team leader will be responsible for QC the whole
project and organizing between the members. In addition, team leaders are supposed to
meet with Instructor on regular schedule for updates and questions.
3. You should type all written text, dividing the note book into logical sections with tabs
(alternative development scenarios), and include a letter of transmittal to Dr. Salehi
which summarizes the main aspects of one development scenario that you would
recommend, based on your work.
4. Include a brief written description of the discovery and prospect. Include clean copy of
reservoir map.
5. Determine the number of wells required to produce each structure, assuming that all
future exploratory wells are successful. Include a sheet showing how you calculated the
number of production and injection wells to develop the structures.
6. Develop a well design plan including the mud weights for each section based on having
the mud window from the offset logs, directional drilling plan, casing design, hydraulics
and contingencies*
(You may assume horizontal or multilateral wells but if you do, well costs should increase
by an appropriate factor).
7. Assuming one of the wells is tested @ a constant rate of 1500 stb/day for a period of 100
hours. It is suspected from seismic & geological evidence, that the well is draining an
isolated reservoir block which has approximately a 2:1 rectangular geometric shape &
extended drawdown test is intended to confirm this. Reservoir data & following bottom-
hole pressure recorded during test are detailed below:
h = 20 ft Ct = 15.10^-6 psi^-1
rw = 0.33 ft µo = 1 cp
φ = 0.18 Bo = 1.20 rb/stb
3. Time (hrs) pw (psi) Time (hrs) pw (psi) Time (hrs) Pw (psi)
0 3500 (pi) 7.5 2848 50 2597
1 2917 10 2830 60 2545
2 2900 15 2794 70 2495
3 2888 20 2762 80 2443
4 2879 30 2703 90 2392
5 2869 40 2650 100 2341
a) Calculate effective permeability & skin factor of the well.
b) Estimate the area being drained by the well.
*Use IHS software in computer lab for all calculations.
*Note: Instructions will be given on requirements for directional well plan, offset well data to
predict PP/FG, hydraulics and other details.
8. Based on this plan, locate all wells on a copy of your reservoir map (use a “•” For oil/gas
wells and a “φ” for injection well, if any). The number of wells desired may or may not be
the same for each development scenario.
9. Once the number and placement of wells has been determined, formulate a
delineation/development well drilling schedule and specify the type of rig(s) to be
contracted.
10. THE GROUP MEMBERS SHOULD INVESTIGATE A DIFFERENT DEVELOPMENT ALTERNATIVE
(AT LEAST THREE) AND REPORT THESE IN SEPARATE SECTIONS OF THE BINDER, WITH
SIGNATURE PAGE.
To do this, each member should select an overall development scheme for the field. What
you are to decide here is what principal facility will be used to develop the field, e.g. will you
use a conventional fixed structure, concrete gravity, TLP, SPAR or subsea development with
floating production vessel to develop the field?
Make a list of all the major components you will require in your field development scheme,
and write 1-2 pages of text that describes the development.
Include a copy of the reservoir map showing well locations, a small “X” on the field map for
the proposed location of any central facility/subsea templates or manifolds envisaged.
11. Identify how you will transport the oil/gas to the processing facility and to market. If
pipelines are to be constructed, indicate their route, tie-ins, and any facilities which you
plan to share. If you plan to tie into another line, you must indicate this in your plan. If
other transportation schemes are envisaged, then describe these.
4. 12. Based on the number of wells you calculated, and their drilling and completion schedule,
forecast a general production stream.
13. Based on the development and construction times given as data, draw a field
development schedule for your proposed development scheme. Be sure to show the
fabrication and installation (If any preliminary studies, development drilling, etc.).
14. Develop a rough estimate of project development costs (i.e. capital costs) based on the
capital cost information given.
Note: You will need to find the cost associated with each category you specified on your
schedule. Be careful to multiply costs/well or costs/mile by the appropriate factors.
15. Based on the timing shown in your bar chart, and the total costs for each category
determined in step 12, develop an estimate of the capital costs required per year.
(For example, assume a platform costs 800MM$ to fabricate and install from June 2000- June
2002. Then, 25% of the costs are incurred in 2000, 50% are in 2001 and 25% are in 2002.
Apply this cost scheduling to all categories in your project schedule and sum the total cost for
each year).
16. Estimate the annual operating expenses for the project using the operating cost
information given.
(Note: The annual expense is normally estimated as a percent of the total project capital
costs plus any transportation charges and well work over expenses. You will therefore need
to determine a base annual operating expense and increase this expense in the years when
well work overs are likely to occur. Add transportation charges as appropriate to your
development scheme).
17. Complete the economics worksheet (you can automate this if you like) to calculate the
“present value” of the development scheme. Follow the instructions given under
“FORMULAE AND INSTRUCTIONS FOR COMPLETING PROJECT ECONOMICS”.
18. Based on your results, each group member should prepare a paragraph(s) to your team
leader making a recommendation about the scenario investigated. Is this the way to
develop the field?
5. EXPECTED DEVELOPMENT TIMES FOR VARIOUS PROJECTS TASKS
TASK DURATION
Delineation drilling (per well) & Reservoir Evaluation 3 Months
Preliminary engineering studies 4 Months
Contractor bids and bid award 2 Months
Detailed engineering studies 6 Months
Development well drilling/ pre-drilling 3 months/well
Tiebacks/subsea completions 30 days/well
Major production facilities fabrication
Conventional steel platform 27 Months
Concentrate gravity platform 33 Months
TLP 31 Months
Floating production facility (convert semi-submerged) 22 Months
Major production facilities Installation
Conventional steel platform 2 Months
Concentrate gravity platform 15 days
TLP 3 Months
Floating production facility 15 days
Flow line fabrication, installation and tie-ins
Fabrication 15 days/mile
Installation 6 days/mile
Tie-ins 22 days/well
Export pipeline fabrication 19 months
Export pipeline installation 13 months
SPM fabrication 15 months
SPM pipeline installation 3 months
Facilities hookup and commissioning 3 months
Startup 11 days
Construction of new refinery 35 months
6. EXPECTED PROJECTS COSTS (CAPITAL EXPENSE)
CATEGORY COST, MM $
Engineering management 60
Well
Producers (*)
Conventional or concrete gravity platform w/tieback 22/well
TLP w/tieback 24/well
Subsea template 25/well
Subsea satellite 27/well
Injector (*)
Conventional or concrete gravity platform w/tieback 22/well
TLP w/tieback 24/well
Subsea template 25/well
Subsea satellite 27/well
Umbilical and Flow lines (including 2 tie-ins per line) 1.2/mile
Export subsea pipeline 2.4/mile
SPM 16.7
Production facilities
Conventional steel jacket see chart
Foundation and topsides 40$/dry op ton
Concrete gravity platform w/topsides 300
Floating production vessel (converted semi) w/topsides see attached sheet
Production/injection risers “
Subsea manifolds “
Subsea chokes and controls “
LNG Facility $.60/MCF
New Refiner on Angola Shore 600
(Angolan govt. to pay 60% of costs)
Refinery throughput $.50/stb
(*) Note-costs are for deep water wells. Shallow water wells are 40% of this cost.
7. SPONSER INFORMATION
GENERAL INFORMATION
TLP (LARGE) $600MM
TLP (SMALL) $450MM
SPAR (LARGE) $450MM
SPAR (LARGE) $450MM
FPS $450MM
FPSO $450MM
SUBSEA PIPELINES $3MM/MILE
SUBSEA UMBILICALS $2MM/MILE
DEEPWATER RISERS $4MM EACH
OPERATING RISERS $TLP/SPAR $3/BBL
FPSO $4/bbl.
SATELLITE PROCESSING AT HOST $3.0/bbl.
SUBSEA SATELLITE OPEX $1.5/bbl.
SUBSEA MANIFOLD $30MM
DRILLING COST $30MM PER WELL
COMPLETION COST (SUBSEA) $6MM PER WELL
SUBSEA CONTROL/MEASUREMENT PACKAGE AT HOST - $30 MM
8. FORMULAE & INSTRUCTIONS FOR COMPLETING
PROJECT ECONOMY
1. Oil price. You are given an oil price in US $80 per bbl. (In actual circumstance project
costs may be paid in foreign currency and the exchange rate for each year would need
to be included in the project economies). What is the official currency in Angola???
2. Gross oil/gas production. You should be able to calculate how much oil and gas the field
will produce based on the production profile per well and the number of producing
wells you calculated for the development. Be sure to enter production numbers in
MMBO (millions of barrels) and/or MMSCF.
3. Gross revenue. This is the total revenue generated by the production. It is equal to the
gas oil production in each year times the oil price for that year, plus the gross gas
production times the gas price for that year. Be sure to deduct a fuel gas allowance.
4. Royalty. Governments/Individual grantors of leases take a royalty “off the top”, i.e
before any expenses or taxes are deducted. Royalties are normally based on a sliding
scale offshore, which means the more you produce the larger your royalty. Angola’s PSC
has an 8% royalty which is constant, regardless of the production level. (some contracts
increase the royalty with increasing production rate).
5. Net revenue. The revenue which the company earns after royalty is deducted but before
expenses is paid. Net revenue = gross revenue *(1 – royalty fraction).
6. Operating expenses. The total cost of operating the production facility, working over
wells and paying to transport and process hydrocarbons. Calculate this for each year
based on your development scenario and operating cost data given.
7. Operating income. Operating income is the income after operating expenses are
deducted. Operating income = net revenue – operating expense.
8. Taxes. Normally there are many different types of taxes which must be accounted for in
various ways. Here we will assume a constant corporate tax rate of 35%
9. Net income. This is the after tax income to the company. That is, for each year, net
income = operating income-tax.
10. Capital expenses. This is the total investment in tangible, depreciable assets, such as
equipments and platforms. You should have calculated the total capital costs for each
year of the project development from the project schedule and information on capital
expense. Enter amounts for each year.
11. Cash flow. The total cash the company has available from the project after capital costs,
debt repayment, dividend payments, etc. For our exercise, calculate the cash flow = net
income – capital costs.
12. Discount factor. Discount factor is the factor applied to future values to equate them on
the same basis as current dollars. Discount factor for simple compounding = 1(1+I)^t ,
9. where I is the period interest or inflation rate and t ƩTable 6 are calculated based on a
6% interest rate and t in integers (0,1,2, etc.) reflecting years.
13. Discounted cash flow. This is the cash flow for each year times that year’s discount
factor.
14. Present value or present worth. The cumulative sum of the discounted cash flow. That
is,
PV = ƩDCFt
Where,
PV = present value
DCF = discount cash flow
t = time period, year
n = number of final time period in project life
10. EXPECTED PROJECT COSTS (RECURRENT OPERATING EXPENSE)
Annual Well Operating Expenses Cost
Conventional steel platform na
Concrete gravity platform na
TLP na
Floating production facility na
Well Work overs (*)
Producers/Injectors (assume same costs) Costs, MM$
Conventional or concrete gravity platform tieback 4.0/well
TLP tieback 4.0/well
Subsea template 6.1/well
Subsea satellite 6.0/well
Transportation & Processing Expenses Cost
FSPO/SPM – tanker option
Tanker shuttles $0.60/bbl
LNG tanker transport see previous table
( ($1.5/stb)
Pipeline throughput (existing lines) $0.50/bbl
New pipeline options $0.7/bbl
*Assume producing wells will require full work overs every 6 years. You can schedule well work
overs all at one tome (in a single year) or spread them over several years accommodation
would be to spread them over several years. Be sure to fully explain what you did or assumed.
11. TABLE 1
OIL RESERVES
Structure Areal Size
(acres)
OOIP
(Original oil
in place)
(MMBO,
million
barrels oil)
Recoverable
Oil
(MMBO)
# of
Producing
Wells
Required
# of
Injection
Wells
Required
Name 32670 68.0 25.22
Name 3594 8.5 1.94
Name 4744 10.9 3.88
Name 7187 15.0 5.82
Total 99.4 36.86
