TECHNICAL AND ECONOMIC VIABILITY OF
PRODUCING MARGINAL OIL FIELDS IN THE
NIGER DELTA USING WATER INJECTION
BY
RITA ONOLEMHEMHENCo Authors: S.O Isehunwa, P. A Iwayemi, A.F Adenikinju
CENTRE FOR PETROLEUM, ENERGY ECONOMICS AND
LAW,
UNIVERSITY OF IBADAN
1
OUTLINE
Introduction
Background of Study
• Literature Review
• Research Methodology
• Results and Analysis
• Conclusion and Recommendation
2
Introduction
A Marginal oil field is:
• Any oil discovery whose production would, for whatever reasons, fail to match the desired or established rates-of-return of the leaseholder (Egbogah, 2012).
• Any field that has reserves booked and reported annually to the Department of Petroleum Resources (DPR) and has remained unproduced for a period of over 10 years.
• According to the US Legal.com, marginal field refers to an oil field that may not produce enough net income to make it worth developing at a given time. However, should technical or economic conditions change; such fields may become commercial fields.
• Mainly characterized by low reserves and are economically sensitive to develop.
3
Introduction(cont’d)
Water Injection:
Is the process of injecting water into the aquifer through one or more injection wells surrounding one or more production wells for the purpose of maintaining pressure inside the reservoir to achieve optimum production and maximize ultimate recovery.
Recovery factor is:
Defined as the fraction of hydrocarbon in place thatcan be recovered or the equivalent measure of theultimate hydrocarbon recovery (Muskat, 1949)
4
Background of Study Marginal fields are currently-
• estimated to contribute about 30% to 40% of global oil
produced and about 3 to 4% percent of the total crude
production in Nigeria.
• gaining a growing importance due to the natural
production decline of large, mature fields.
Federal Government incentivized the development of
marginal fields to small indigenous production companies:
2003 award of 24 marginal fields to 31 companies
2013 award of 6 marginal fields to 4 companies
5
Marginal Fields distribution in the Niger Delta
Table1: DISTRIBUTION OF MARGINAL FIELDS IN DIFFERENT NIGER
DELTA TERRAINS
FIELD SIZE TERRAIN TOTAL
LAND SWAMP OFFSHORE
0-10MM bbl 51 21 7 79 43.17%
10.1-20MM bbl 37 22 24 83 45.36%
20.1-50MM bbl 3 7 11 21 11.47%
TOTAL 91 50 42 183
49.73% 27.32% 22.95%
Source: Oil and gas Journal, 2011
6
Source: Field Development Lecture Note (Isehunwa, 2006)
7
Figure 1:Historical Trend of Total Crude Oil Production vs Marginal oil Fields Production in Nigeria. Source: NNPC Statistical Annual
Bulletin, 2015
2015, 23291697
2015, 773458592
0
100000000
200000000
300000000
400000000
500000000
600000000
700000000
800000000
900000000
1E+09
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Pro
du
ctio
n (
bb
ls)
Year
Marginal production Vs Total Production
Marginal Fields
Total Oil Production
Research Problem
Marginal fields are usually produced under primaryrecovery method due to the economically sensitivenature of such fields, which leaves a huge fraction of theoriginal oil in place (OOIP) in the ground.
There has been a decline in Nigerian’s oil reserves whichis put at 37billion barrels. However, the governmentprojects a reserve of 40billion barrels by 2020 (NNPC:2016). Therefore, there is a need to economicallyimprove oil recovery
Hence, this study was designed to investigate increasedoil recovery from marginal oil fields within an economicframework.
8
Research Questions
Can water injection improve recovery in
marginal oil fields?
How will the incremental recovery justify the
investment?
9
Objective of Study
Broad Objective:
To determine the economic viability of incremental reserves arising from the use of water Injection to improve recovery of marginal oil fields.
Specific Objectives:
To estimate recovery factor under primary and secondary recovery.
To determine the incremental recovery from the use of water injection in marginal oil fields.
To determine the economic viability of water injection in marginal oil fields.
10
Justification of Study
Improving recovery for marginal oil fields will
improve their economics and will make these
fields attractive to investors
The development of marginal oil fields can
increase oil reserves and promote local
content.
11
Scope of Study
The scope of this study is: Limited to oil reservoirs which have partial water
drive mechanism and solution gas drive mechanism
in the Niger Delta region.
Limited to oil reservoirs that are marginal at the
point of discovery or oil fields that have only been
produced under their primary energy.
The impact of factors such as political,
environmental and social factors were not captured
in this study. 12
Literature ReviewAuthor
Year
Geo
location
Purpose of study Methodology Findings
Abbas, et al
2015
Russia Studied the effect of
water relative
permeability reduction
during low salinity
waterflooding on
improved oil recovery
3D reservoir simulation The sensitivity study shows
that the incremental recovery
increases for relative
permeability reduction.
Xin, et al
(2009)
China Analyzed the water
injection optimization for
a complex fluvial heavy-
oil reservoir
Integration of Geological,
Seismic and Production
Data.
The responses from the
water injection were very
positive and resulted in stable
reservoir pressure and
increased oil production
pressure.
Bruno, et al
(2008)
Abu
Dhabi
Reviewed the water
injection strategy of a
carbonate oil field
Reservoir simulation
model and history
matched for both pressure
and saturation changes was
used to compute voidage
replacement ratio
Results of the model
indicated that crossflow
magnitude was minimized
when certain pressure
differences were maintained
between the reservoirs.13
Gulstad
(1995)
America conducted a study on
the determination of
hydrocarbon reservoir
recovery factor by
using multiple linear
regression technique
for water drive and
solution gas drive
reservoirs in sandstone
and carbonate
reservoirs.
He however observed that
initial oil in place (OOIP)
had a strong correlation
with recovery factor both
in water drive and solution
gas drive reservoirs. He
also pointed out in his
study, that heterogeneity is
important to consider when
developing recovery factor
mode
𝑅𝐸𝐶 = −264.0.34 𝑂𝑂𝐼𝑃 +
29.37𝐼𝑛 𝑅𝑠𝑖 − 0.06 𝜆𝑜 +
10.70𝐼𝑛 𝜆𝑜 − 12.64𝐼𝑛(ℎ)
𝑅𝐸𝐶
= −279 + 0.44 𝑂𝑂𝐼𝑃
− 56.70𝐼𝑛 𝜇𝑜𝑎
− 119.45𝐼𝑛 𝑆𝑤
+ 0.04 𝑃𝑒𝑝 − 4.73 𝜇𝑜𝑖
+ 4.38 𝜇𝑜𝑎
+ 0.24 𝑂𝑂𝐼𝑃 𝐶𝑎𝑙𝑐
− 0.88 𝑇
Guthrie and
Greenberge
r
1955
N/S Developed a model to
estimate Recovery
factor
empirical correlations for
prediction of recovery
factor performance were
investigated by statistical
study of recovery factor
performances
ER = 0.2719log k + 0.25569
Swi – 0.1355log ( o) – i.5380
- 0.00003488H + 0.11403
Arps et al
1956
N/S Developed a model to
estimate primary
Recovery factor
Statistical method to
develop a correlation
model
RF =
Isehunwa
and
Nwanko
1994
Niger
Delta
Developed a model to
estimate primary
Recovery factor
Least Square Method
RF = C *
14
Although, much research has been done on
water injection, marginal field development and
recovery factor estimation. However, there is a
dearth in literature on the technical and
economic evaluation of this production
technique in the Nigeria’s marginal oil fields.
15
Gap in Literature
Theoretical Framework
The least square equation is presented as;
Recovery factor can be related to reservoir parameters
using Eq.(1), the coefficients of a, b, and c can be
determined. Recovery factor is expressed as:
𝑅. 𝐹 = 𝑓(𝜇𝑜, 𝑆𝑜𝑟 , 𝑅𝑠𝑖 , 𝑃, 𝐴𝑃𝐼)
𝑌𝑖 = 𝑎𝑋𝐼2 + 𝑏𝑋𝐼 + 𝐶 …………………………………….. (1a)
16
𝑅2 = 1 – ( (𝑅𝐹−𝑅𝑒𝑠𝑒𝑟𝑣𝑜𝑖𝑟 𝑃𝑎𝑟𝑎𝑚𝑒𝑡𝑒𝑟 )^2 𝑛𝑖=1
(𝑅𝐹−𝑇𝑜𝑡𝑎𝑙 𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑅𝑒𝑠𝑒𝑟𝑣𝑜𝑖𝑟 𝑃𝑎𝑟𝑎𝑚𝑒𝑡𝑒𝑟 )^2𝑛𝑖=1
) ………………………….(1b)
Research MethodologyThe Technical Model
Data from 136 reservoirs having water drive mechanism and
129 reservoirs having solution gas drive mechanism were
collected from the Niger Delta. 13 reservoir parameters
(reservoir thickness, porosity, permeability, oil viscosity, water
viscosity, temperature, API gravity, reservoir pressure,
formation oil volume factor, original oil in place, solution gas-
oil ratio and residual oil saturation) were adopted to develop
the recovery factor models.
The residual oil saturation for the reservoirs were estimated
using the model of (Isehunwa and Nwankwo,1994) for Niger
Delta fields.
17
Input Parameters for the Technical Model
18
Input parameter for solution gas drive model
Reservoir Parameter L (15%) M (50%) H (85%)
Reservoir thickness ( h)ft 12 26 80
Porosity (Ø) 0.126 0.178 0.28
Permeability (K)mD 10.9 79 380
Oil Formation vol. factor
(Boi) bbl/stb
1.1 1.26 1.498
Solution-gas oil ratio (Rsi)
scf/stb
187 480 909
API gravity(oAPI) 27.4 38 43
Reservoir pressure (P)Psi 1120 2044 3755
Input parameter for water drive model
Reservoir Parameter L (15%) M (50%) H (85%)
Reservoir thickness ( h)ft 12.36 30.3 90.8
Porosity (Ø) 0.17 0.28 0.32
Permeability (K)mD 140 440 1686
Temperature (T) k 123.2 170 208.8
Residual oil saturation
(Sor)
0.08 0.13 0.21
API gravity(oAPI) scf/stb 24.54 34.1 41
viscosity (µo) 0.37 0.85 5.9
Research Methodology Cont’d Preliminary Screening
S/N Correlation of Rf with
Reservoir Parameters
R2 Correlation Model input parameter
1 Rf vs OIIP 0.157 Very weak None
2 Rf vs Bio 0.011 No correlation None
3 Rf vs Swi 0.011 No correlation None
4 Rv vs Pi 0.493 Good correlation Solution gas drive
5 Rv vs h 0.045 No correlation None
6 Rf vs μo 0.88 Very strong Water drive, Solution gas
drive
7 Rf vs Ø (porosity) 0.007 No correlation None
8 Rf vs K 0.003 No correlation None
10 Rf vs API 0.582 Good correlation Solution gas drive
11 Rf vs Rsi 0.52 Good correlation Solution gas drive
12 Rf vs μw 0.321 Weak correlation None
13 Rf vs Sor 0.852 Very strong correlation Water drive, Solution gas
drive
19
Research Methodology Cont’d
The final equation for recovery factor for water drive
reservoirs is
20
𝑅𝑓𝑤 = 𝛼𝑖𝑥2 − 𝛼2𝑥 + 0.7432 …………………………….(1)
Where
𝛼1 = 0.0527
𝛼2 = 0.1909
𝑥 = (0.41𝜇0 + 𝑆𝑜𝑟 )
𝜇0 = Oil viscosity
𝑆𝑜𝑟 = Residual oil saturation
Research Methodology Cont’d For solution gas drive mechanism, the recovery factor is given as :
Where; a= 0.127, b= 0.0218, c= 0.0341, d= 0.1924
For the secondary recovery model, pressure is expressed as;
𝑃𝑠 = 0.0279𝑉𝑤𝑖𝑛𝑗 + 1069.5 (4)
While Sor is expressed in terms of
𝑆𝑜𝑟 = 0.430211 + 0.042846Inμo − 0.06733Swi ……………………………… (5)
Substituting Eq.(4) and (5)
𝑹𝑭𝒔 = 𝑪𝑭(𝟎. 𝟏𝟐𝟕𝝁𝒐−𝟎.𝟏 + 𝟎. 𝟎𝟐𝟏𝟖𝑨𝑷𝑰𝟎.𝟒𝟖𝟕 + 𝟎. 𝟎𝟑𝟒(𝟎. 𝟎𝟐𝟕𝟗𝑽𝒘𝒊𝒏𝒋 + 𝟏𝟎𝟔𝟗.𝟓)𝟎.𝟏𝟔𝟏 − 𝟎. 𝟎𝟎𝟖𝟐𝟒𝟒𝑰𝒏𝝁𝒐 +
𝟎. 𝟏𝟏𝟔𝟖𝟓𝟎𝑺𝒘𝒊 − 𝟏. 𝟔𝑬−𝟖𝑹𝒔𝒊 + 𝟎. 𝟏𝟗𝟖𝟔𝟐𝟕) ………………………………………………………(6)
𝑹𝒇 = 𝒂𝝁𝒐−𝟎.𝟏 + 𝒃𝑨𝑷𝑰𝟎.𝟒𝟖𝟕 + 𝒄𝑷𝒊𝟎.𝟏𝟔𝟏 − 𝒅𝑺𝒐𝒓 − 𝟏.𝟔𝑬−𝟖 𝑹𝒔𝒊𝟐 + 𝟎.𝟐𝟖𝟏𝟒 ………. (3)
21
Research Methodology Cont’d The Economic ModelThe rate of production and annual production for the subsequent years were obtained
using the exponential decline equation.
𝒒𝒕 = 𝒒𝒊𝒆−𝑫𝒊𝒕 (7)
Oil produced from time t=0 to any other time is given as
△𝑵𝒑 =(𝒒𝒊−𝒒𝒕)∗𝟑𝟔𝟓
𝑫𝒊 (8)
And the time required to produce △Np is given as
𝒕 =𝑰𝒏
𝒒𝒊𝒒𝒕
𝑫𝒊 (9)
Where
qt = rate at any time t of production, BOPD
qi = initial rate of production, BOPD
t = time period between qi and qt, years
Di= nominal decline rate, fraction per year
ΔNp = Cumulative production during the time period, Stb.
22
Economic Model
The Economic Indicators of investment profitability
used for this study are;
𝑁𝑃𝑉 (𝑖, 𝑁) = 𝑡=0𝑁 𝑅𝑡
(1+𝑖)𝑡(10)
IRR is given as :
𝑁𝑃𝑉 = 𝑡=0𝑁 𝑅𝑡
1+𝑖 𝑡 = 0 (11)
Profitability Index= Present Value of Future Cash Flows Generated by the Project
Initial Investment in the Project (12)
23
Cash Flow model parameters Gross revenue= Annual Production × Oil Price
Cost (CAPEX & OPEX)
Abandonment cost
Royalty is % of Gross revenue (sliding scale royalty, ranges
between 2.5% to 18.5% for production of <5000bbl/d to >25000
overriding royalty (2. 5 to 7.5%)
NDDC charge = 3% of total cost
Investment tax allowance =20% of tangible CAPEX
VAT (value added) = 5%
Cost recovery = 80% of revenue after deducting royalty
Discount rate (opportunity cost of an investment) = 10%
(referenced to Muonagor & Anyadiegwu, 2013)
Oil price (referenced to Awotiku , 2011)
Petroleum profit tax = (official rate is 55%, unofficial rate is 65.75%)
24
Research Methodology Cont’d Table 2: The Base Inputs for the Cash flow Model
STOIIP 116 million
RF 0.59
Reserves 68.44
Cost per foot 150 $ 12.775
Average well depth 4,320 ft 12.742
Cost of drilling 1 producing well 648,000 $ 11.866
Cost of well head 10,000 $ 10.950
Cost 1 well 658,000 $
Cost of hiring MOPU and FPO 100,000 $ per day
PHASE 1 PHASE 2 NORTH FAULT BLOCK
Cost of 6 producing wells 3.948 MM$ Cost of 5 producing wells 3.29 MM$ Cost of 3 producing wells
Cost of drilling 1 injection well and water injection lines 0.9186 MM$ Injection well 0.9186 Injection well
cost of water injection pump 0.208 MM$ cost of water injection pump 0.208 MM$ cost of water injection pump
Total Cost of MOPU and FPO 219 MM$
TOTAL CAPEX 231.5918 MM$ Cost Recovery Limit 50%
Discount Rate 10%
Annual OPEX (30 staff+maintenance+accommodation) 10.44 MM$
Working interest (Pre-cost recovery) 100%
Post cost recovery 50%
Net profit interest 70% 30% due to original field owners
SLIDING SCALE ROYALTY
Daily production, bbl Rate
From To %
0 5000 2.5
5000 10000 7.5
10000 15000 12.5
15000 25000 18.5 18.50%
25000 No limit unless
negotiated
Oil Price 25 $/stb Royalty 12.50% US dollar inflation rate 2.00%
BASE INPUTS
25
Results and Analysis
Table 3: Results for water drive model
26
INPUT PARAMETERS RESULTS
Sor oil vis Swi Rf
I&N
Model
Coy
model G & G
Present
Model
0.29 0.2 0.12 0.67 0.57 0.45 0.58 0.68
0.27 0.5 0.22 0.65 0.56 0.56 0.44 0.66
0.26 0.25 0.19 0.67 0.58 0.53 0.48 0.68
0.34 1 0.15 0.64 0.51 0.38 0.52 0.64
0.32 0.91 0.17 0.61 0.52 0.49 0.56 0.64
0.32 2.4 0.25 0.57 0.49 0.51 0.4 0.58
0.28 2.2 0.3 0.6 0.5 0.48 0.35 0.59
0.16 0.7 0.42 0.72 0.61 0.04 0.37 0.66
0.21 4.2 0.47 0.6 0.52 0.1 0.24 0.58
0.35 4.1 0.23 0.55 0.46 0.55 0.38 0.58
0.23 0.61 0.3 0.67 0.57 0.45 0.42 0.66
0.28 0.24 0.15 0.67 0.57 0.75 0.59 0.68
Result and Analysis
27
Results and Analysis Table 4 : Result of the solution gas drive model
28
Results and Analysis
Table 5 :Result for Secondary Recovery factor model
29
RESERVOIR Present Work's
Model (RFs)
primary recovery
factor RFp Incremental RF
RESERVOIR 1 0.592632 0.490168 0.102465
RESERVOIR 2 0.541031 0.490168 0.050863
RESERVOIR 3 0.561429 0.315302 0.246127
RESERVOIR 4 0.506128 0.315302 0.190826
RESERVOIR 5 0.589312 0.315302 0.27401
RESERVOIR 6 0.600666 0.480886 0.11978
RESERVOIR 7 0.576351 0.390045 0.186307
RESERVOIR 8 0.571407 0.390045 0.181362
RESERVOIR 9 0.574493 0.480886 0.093607
RESERVOIR 10 0.542463 0.390045 0.152418
RESERVOIR 11 0.719616 0.450448 0.269168
RESERVOIR 12 0.583895 0.450448 0.133447
RESERVOIR 13 0.609453 0.201951 0.407502
RESERVOIR 14 0.598801 0.450448 0.148352
RESERVOIR 15 0.598768 0.450448 0.14832
RESERVOIR 16 0.65336 0.450448 0.202911
Table 6: Cash flow Analysis for Base Case
30
Results and Analysis Cont’d Table 7: Cash Flow Analysis for Onshore marginal fields
Year Nominal
Price
Inflation-adjusted
Price time,yrs Development
cost, MM$
Tangible dev.
CAPEX
Intangible deV.
CAPEX+OPEX Production,
MMSTB
Cum. Production,
MMSTB Gross
Revenue,MM$ Royalty Rate % Royalty ,
MM$
Net Revenue,
MM$
70% 30%
2011 0 231.5918 162.11426 69.47754
2012 86.46 88.19 1 10.220 10.220 883.621 12.6% 111.399 772.222
2013 91.17 94.85 2 9.676 19.896 882.175 12.3% 108.295 773.879
2014 85.60 90.84 3 8.800 28.696 753.293 11.7% 87.785 665.508
2015 42.50 46.00 4 8.140 36.836 345.929 11.1% 38.401 307.528
2016 37.00 40.85 5 7.227 44.063 267.399 10.2% 27.186 240.213
2017 37.00 41.67 6 6.643 50.706 245.791 9.4% 23.188 222.603
2018 37.00 7 6.242 56.947 230.936 8.9% 20.440 210.496
2019 37.00 8 5.548 62.495 205.276 7.6% 15.693 189.583
2020 37.00 9 5.256 67.751 194.472 7.3% 14.180 180.292
OPEX, MM$
DEV. CAPEX CAPITALIZED,$MM
Cost Recovery,
MM$
Cum Cost Recovery
$MM VAT, 5%
(CAPEX+OPEX) Abandonment
cost(MM$)
Educational Tax (2% of
Access profit), $MM
Investment Tax
Allowance, $MM
Total Tax, $MM
Profit Oil, $MM
Cost Oil, $MM
50%
0.00 0.00 0.00
10.44 9.01 78.48 78.48 12.10 117.486602 0.00 32.42 12.10 871.39 12.23
10.44 9.01 9.01 87.49 0.52 54.6449313 0.00 0.00 0.52 881.53 0.64
10.44 9.01 9.01 96.50 0.52 25.4162471 0.00 0.00 0.52 752.65 0.64
10.44 9.01 9.01 105.50 0.52 11.8215103 0.00 0.00 0.52 345.30 0.63
10.44 9.01 9.01 114.51 0.52 5.49837688 0.00 0.00 0.52 266.78 0.62
10.44 9.01 9.01 123.52 0.52 2.55738459 4.19 0.00 35.38 210.32 35.47
10.44 9.01 9.01 132.52 0.52 1.18948121 3.98 0.00 35.28 195.56 35.37
10.44 9.01 9.01 141.53 0.52 0.55324707 3.57 0.00 35.10 170.10 35.18
10.44 9.01 9.01 150.53 0.52 0.25732422 3.39 0.00 35.02 159.38 35.09
31
Results and Analysis Cont’d
The NPV and IRR Calculation
PO/Gt, $MM PO/It, $MM Accessible Profit,
$MM PPTbase, $MM PPT,$MM NCF Investor's Take (MM)
0.00 0.00 $ (231.59)
609.98 261.42 574.82 0.00 0.00 $ 139.70
617.07 264.46 708.79 0.00 0.00 $ 145.85
526.86 225.80 629.65 0.00 0.00 $ 127.69
241.71 103.59 285.27 0.00 0.00 $ 54.86
186.74 80.03 224.28 0.00 0.00 $ 42.51
147.22 63.09 209.61 55.76 30.67 $ 29.56
136.89 58.67 198.87 55.97 30.78 $ 27.88
119.07 51.03 178.59 56.38 31.01 $ 24.97
111.57 47.81 169.59 56.56 31.11 $ 23.27
NPV $228.25 MM
IRR 45.71%
32
The breakeven price for this project is $21
The profit to investment ratio is
𝑃𝐼 =𝑁𝑃𝑉
𝐼𝑁𝑉𝐸𝑆𝑇𝑀𝐸𝑁𝑇 𝐶𝑂𝑆𝑇
From the table (15), the NPV is $228.25MM and the investment cost is $231.5918MM
𝑃𝐼 = 228.25
231.5918
𝑃𝐼 = 0.985
Recall that when the discounted cash flow (NPV) is used, the break even value is 0.0 while
for the undiscounted net cash flow, the break even is 1.0. with a PI of 0.985, the project is
economically viable.
Results and Analysis Cont’d
Table 8 : Cash flow Analysis for Offshore fields
33
NPV, IRR and P1Calculation for Case 3
34
Results and Analysis Cont’d The Probabilistic Approach
The Monte Carlos simulation was used to generate the distribution shown in
figure 2;
35
Risk and Sensitivity Analysis for Onshore water injection
project
36
Risk and Sensitivity Analysis for Offshore water injection project
37
NPV vs RF
38
-100
0
100
200
300
400
0 20 40 60 80
NP
V (
MM
$)
RF (%)
NPV vs RF @ $25, $50 & $75
NPV(MM$)@ $25
NPV(MM$)@ $50
NPV (MM$)@ $75
-50
0
50
100
150
200
250
300
350
0 50 100
NP
V (
MM
$)
RF (%)
NPV vs RF @ 5%,10%, & 15%
NPV(MM$)@5%
NPV(MM$)@10%
NPV(MM$)@15%
Conclusion In conclusion, water injection project for marginal field
is technically and economically viable and will give good
returns on investment under the technical and
economic conditions established in this study. With the
help of the range of the economic indices shown in the
results obtained, it is a project that marginal field
operators should be willing to undertake. However, the
discount rate, development cost and oil price are the
key to making final investment decision in the project.
39
Recommendation and Policy Implication
Based on the findings from these analyses, the following recommendations were made:
Firstly, water injection project should be considered as a development plan in developing a marginal field as this study has shown that it will not only increase production and reserve but it will extend the economic life of the field.
Secondly, the recovery factor must be above 20%. Water injection should also be initiated in the early life of a field that proves to be a good candidate for water injection to prolong the life of the field and to maintain production from such fields.
The policy implication of this study is that government should continue the five (5)year tax holiday policy for new marginal field operators.
40
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