Nov 05, 2015
INSTITUTE OF PETROLEUM STUDIES
June 2015
Dynamic Reservoir
Simulation of the Alwyn
Field using ECLIPSE TM
NWOSU UGONNA DIXON IPS/MSC/PPD/2014/240
IJEH GIFT ISIJOKELU IPS/MSC/PPD/2014/235
NWOSU, DIXON 1 IJEH, ISIJOKELU
EXECUTIVE SUMMARY
This project proposes an optimized development plan for production of the Alwyn North reservoir
through the maximization of total oil production at minimum cost per barrel. A black oil model was
simulated using Eclipse for the determination of the field oil recovery, among other parameters such as
field oil production rate and field water cut, of four development scenarios: natural depletion, water
injection, gas injection and water-alternating-gas injection. Each development scenario was optimized for
number, location, completion and geometry of production and injection wells as applicable.
Natural depletion was simulated by depleting the reservoir to a bottom-hole pressure limit 0f 100 bars
using four already-drilled wells. The field oil recovery was 30 % and the duration of the production
plateau at 4200m3 was 6 years.
Water injection was simulated injecting water as a secondary recovery mechanism after depleting the
reservoir to a bottom-hole flowing pressure of around 260 bars. Two additional production wells and four
additional injection wells were drilled to give maximum results with this scheme. The oil recovery thus
increased from 30% to about 53% with the production plateau sustained for 3.9 years albeit at a higher
plateau rate of 7200m3
Gas injection was proposed to reduce the high water cut levels associated with water injection by
injecting gas into the reservoir using the same water injection wells. The field oil recovery reduced to
42%.
The Water-alternating gas scheme, using the same injectors and producers as in water injection, gave a
field oil recovery of about 555 with a production plateau sustained for 4.2 years.
Water Injection and Water-alternating Gas stood out clearly in terms of profitability, internal rate of return
and pay-back time. . Water Injection was the best performer with a pay-back time, internal rate of return
and profitability index of 1.2 years, 90% and 3.26. Recommendation on best production scheme was
proposed based on technical criteria, environmental consideration and comparison of economic
parameters.
NWOSU, DIXON 2 IJEH, ISIJOKELU
ACKNOWLEDGEMENT
This project is dedicated to Mrs Elizabeth Nneka Nwosu who departed this earth
on 5th, June 2015. May her soul rest in perfect peace.
Mr Soma Sakthikhumar also deserves a worthy mention for being patient enough
to impart the desired knowledge to us.
Picarq Corporation, Total Nigeria and Institute of Petroleum Studies are also
appreciated for putting the necessary logistics, facilities and finance in place to
make this project a success.
NWOSU, DIXON 3 IJEH, ISIJOKELU
Table of Contents
Executive Summary ...................................................................................................... ii
Acknowledgements iv
List of Tables vi
List of Figures ix
CHAPTER ONE ............................................................................................................... 9
INTRODUCTION ........................................................................................................... 11
1.1 Purpose of study ..................................................................................................... 11
1.3 Geological Description And Field Characteristics .............................................. 11
1.3.1 Location ............................................................................................................... 12
1.3.2 Field Characteristics Tectonics .......................................................................... 13
1.3.3 Geological Setting ............................................................................................... 13
1.3.4 Brent East Reservoir of Alwyn North Field ....................................................... 15
1.3.4.1 Geological Description ..................................................................................... 15
1.3.4.2 Tectonics .......................................................................................................... 16
1.3.4.3 Sedimentology ................................................................................................. 17
1.3.4.4 Log correlations ............................................................................................... 19
1.4 OBJECTIVES OF THE STUDY ............................................................................. 20
1.5 Reservoir Model And Characteristics ................................................................... 21
1.5.1 Rock Typing ........................................................................................................ 22
1.5.2 Reservoir Fluid Properties ................................................................................. 24
1.5.3 Fluids in Place .................................................................................................... 24
CHAPTER TWO ............................................................................................................ 26
FIELD DEVELOPMENT TECHNIQUES ...................................................................... 27
2.1 Constraints ............................................................................................................ 27
NWOSU, DIXON 4 IJEH, ISIJOKELU
2.1.1 Drilling Constraints ........................................................................................... 27
2.1.2 Production Constraint ...................................................................................... 28
2.1.3 Water Injection Constraint ............................................................................... 28
2.1.4 Gas Injection Constraint ................................................................................... 29
2.2 Analytical Calculations ........................................................................................ 29
2.2.1 Case One: Natural Depletion ............................................................................ 30
2.2.1.1 Minimum number of wells .............................................................................. 31
2.2.1.2 Material Balance For Natural Depletion Alone ............................................ 32
a. Rock And Fluid Expansion .................................................................................... 32
i. Tarbert Region: ....................................................................................................... 33
ii. Ness Region: .......................................................................................................... 33
2.2.2 Case Two: Water Injection ............................................................................... 35
2.2.2.1 Material Balance ............................................................................................. 35
i. Tarbert Region: ....................................................................................................... 35
Evaluation of Ea ......................................................................................................... 35
Evaluation of Ed ........................................................................................................ 37
ii. Ness Region ........................................................................................................... 38
Evaluation of Ea ......................................................................................................... 38
2.2.2.2 Estimation of Oil Recovery Using Hand Calculation .................................. 40
Table 2.6: Oil Recovery from Natural Depletion and Water Injection ................... 41
2.2.2.3 Minimum number of wells: ............................................................................ 41
Implication: ................................................................................................................ 43
2.2.3 Case Three: Gas Injection ................................................................................. 44
2.2.3.1 Material Balance ............................................................................................. 44
NWOSU, DIXON 5 IJEH, ISIJOKELU
i. Tarbert Region ........................................................................................................ 44
Evaluation of EA: ....................................................................................................... 44
Evaluation of ED: ....................................................................................................... 44
CHAPTER THREE ......................................................................................................... 49
DYNAMIC FIELD DEVELOPMENT STUDY USING ECLIPSE SOFTWARE ............. 49
3.1 Case One: Natural Depletion ............................................................................. 49
3.1.1 Natural Depletion with the Available Four Exploratory Wells ..................... 49
3.1.2 Effect of Critical Gas Saturation ....................................................................... 52
3.1.3 Natural Depletion with Increased Development Wells: ............................... 54
3.1.3.1 Natural Depletion with Five Producer Wells .............................................. 54
3.1.4 Inferences: Natural Depletion .......................................................................... 57
3.2: Case 2: Water Injection Preceded by Natural Depletion ................................ 58
3.3 Case 3: Gas Injection Preceded by Natural Depletion ....................................... 62
3.4 Case 4: Water- Alternating Gas Injection .......................................................... 63
CHAPTER FOUR ........................................................................................................... 68
ECONOMIC ANALYSIS ................................................................................................ 68
4.1 Economic Evaluation of Natural Depletion at Economic Limit ....................... 70
4.2 Economic Evaluation of Gas Injection Scheme at Economic Limit ................. 72
4.3 Economic Analysis of Water Injection Scenario ............................................... 76
4.4 Economic Analysis of the Water-Alternating-Gas Scheme .............................. 78
4.5 Investment Decision ............................................................................................ 81
4.5.1 Lowest Capital Investment ............................................................................... 82
4.5.2 Pay-back time ................................................................................................... 83
NWOSU, DIXON 6 IJEH, ISIJOKELU
4.5.3 Profitability Index and Economic Life............................................................. 84
4.5.4 Gross Profit Margin per barrel ......................................................................... 85
4.5.5 Cumulative Net Present Value (CNPV): ......................................................... 86
4.5.6 Internal Rate of Return (IRR): ......................................................................... 86
CHAPTER FIVE ............................................................................................................. 88
CONCLUSION AND RECOMMENDATIONS ............................................................ 88
5.1 Conclusion ......................................................................................................... 88
5.2 Recommendations ............................................................................................ 89
REFERENCES ................................................................................................................. 90
APPENDICES .............................................................. Error! Bookmark not defined.
APPENDIX A ............................................................................................................. 92
A1 Natural Depletion: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate
Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor ............ 92
A2 Gas Injection: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate Of
Return , Pay-Back Time And Npv Using 10% As The Discount Factor ................. 93
A3 Water Injection: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate Of
Return , Pay-Back Time And Npv Using 10% As The Discount Factor ................. 94
A4 Natural Depletion: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate
Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor ............ 95
APPENDIX B .............................................................................................................. 96
Evaluation Of Npv For The Various Development Schemes Using The Calculated
Internal Rate Of Return ............................................................................................ 96
B1 Gas Injection: Evaluation Of Npv Using The Calculated Internal Rate Of
Return......................................................................................................................... 96
NWOSU, DIXON 7 IJEH, ISIJOKELU
B2 Water Injection: Evaluation Of Npv Using The Calculated Internal Rate Of
Return......................................................................................................................... 97
B3 Wag Injection: Evaluation Of Npv Using The Calculated Internal Rate Of
Return......................................................................................................................... 98
APPENDIX C .............................................................................................................. 99
Full PVT Report ......................................................................................................... 99
NWOSU, DIXON 8 IJEH, ISIJOKELU
LIST OF TABLES- Table 1.1: Rock Typing and Layers representing the Tarbert and Ness
22
Table 1.2: Initial Values of Fluid Properties ............................................................. 24
Table 1.3: Table Showing the Fluids in Place Volume ............................................. 25
Table 2.1: PVT File ..................................................................................................... 30
Table 2.2: Analytical solution for Recovery by Natural Depletion Drive............... 34
Table 2.3: Reciprocal Mobility Ratio computation for obtaining error. Ea ........... 37
Table 2.4: Relative Permeability (Imbibition) data table ....................................... 37
Table 2.5: Relative Permeability (Imbibition) data table ........................................ 39
Table 2.6: Oil Recovery from Natural Depletion and Water Injection ................... 41
Table 2.7: Gas-Oil Relative Permeability Data for Rock-Type 1 ............................. 45
Table 2.8: Recoveries from combined Natural Depletion and Gas Injection ........ 48
Table 3.1: Comparison of WI and WAG ................................................................... 67
Table 4.1 Revenues and Expenditures for Natural Depletion ............................... 70
Table 4.2 Economic Evaluation Indices for Natural Depletion ............................. 71
Table 4.3 Revenues and Expenditures for Gas Injection 73
Table 4.4 Economic Evaluation Indices for Gas Injection .................................... 74
Table 4.5 Revenues and Expenditures for Water Injection .................................... 76
Table 4.6 Summary of Economic Evaluation for Water Injection
77
Table 4.7 Revenues and Expenditures for WAG Injection ................................... 79
Table 4.8 Summary of Economic Evaluation Parameters for WAG Injection .... 80
Table 4.9: Economic Evaluation for the various development schemes
87
NWOSU, DIXON 9 IJEH, ISIJOKELU
LIST OF FIGURES Figure1.1: Alwyn North Field Localization Map 7
Figure 1.2: Alwyn Area Location Map 8
Figure1.3: Stratigraphy of the Alwyn North Field 9
Figure 1.6: Cross Section Through Alywn Showing The Faults 11
Figure 1.7: Depositional Setting of the Brent Group
Figure 1.8: Showing Log Correlations 13
Figure 1.8: Reservoir Model Showing the Grids 17
Figure 1.9: Data File Initialized to Obtain Volumes In-Place 19
Fig2.1: Reciprocal Mobility Ratio Chart 29
Fig2.2: Fractional Flow curve for the Tarbert Region 31
Fig2.3: Fractional Flow curve for the Ness Region
32
Figure 2.4: Relative permeability versus gas saturation curves 39
Figure 2.5: Plot of Gas Fractional flow against saturation for Tarbert 40
Fig 3.1: Well Architecture: Natural Depletion 42
Fig 3.2: FOPR, FOPT and FOE for the 4-well Natural Depletion case 42
Fig 3.3: Oil Production Rate from Wells PA2, PA1, PN2 and PN1 44
Fig 3.4: Field Recovery Efficiency and Field Plateau Rate for both cases 46
Fig 3.6: Field Water Cut and Field Gas-Oil Ratio for both cases 47
Fig 3.7: Well Architecture: Natural Depletion with Wells 48
Fig 3.9: FPR, FOE, FWCT, FGOR as a function of time 49
Fig 3.10: Well by Well Analysis 50
Fig 3.11: Well Architecture: 7 producers and 5 injectors 52
NWOSU, DIXON 10 IJEH, ISIJOKELU
Fig 3.12: Water Injection: FOPR, FOE and FOPT 53
Fig 3.13: Water Injection: FPR, FWCT and FWIR 54
Fig 3.14: Gas Injection: FOPR, FOE and FOPT 55
Fig 3.15: Water Injection: FPR, FWCT and FWIR 56
Fig 3.16: Sub-case 1: FOPT, FOE, FOPR, FWIR and FOPR 59
Fig 3.17: Sub case 2: FOPR, FOPT, FOE, FWIR and FPR 59
Fig 3.18: Sub case 3: FOPR, FOPT, FOE, FWIR and FPR 60
Fig 3.19: Sub case 4: FOPR, FOPT, FOE, FWIR and FPR 61
Fig4.1 Cash flow curve for Natural Depletion Scheme 67
Fig4.2 Cash flow for Gas Injection 69
Fig4.3 Cash flow for Water Injection 73
Fig 4.4: Cash flow for WAG Injection 75
Fig 4.5: Investment Costs for the various development schemes 76
Fig 4.6 : Pay-back time for the various development schemes 77
Fig 4.7: Economic Life and PI for the various development schemes 79
Fig 4.8 GPM per barrel for the various development schemes 80
Fig 4.9 NPV for the various development schemes 81
Fig 4.10 IRR for the various development schemes 82
NWOSU, DIXON 11 IJEH, ISIJOKELU
CHAPTER ONE
INTRODUCTION
1.1 Purpose of study
To determine the optimum field development plan for the Alwyn North Field
(Brent East Reservoir) in terms of recovery and economics, using Eclipse reservoir
simulator.1.2 Scope of Study
This study was limited to the Brent East panel of the Alwyn North Field. The
reservoir model focused on the Ness 2 and Tarbert 1, 2 and 3 units because of the
small oil content in Ness 1.
Black Oil PVT representation was used in this study. The drive mechanisms were
determined using material balance. Annual production was set at 15% of ultimate
reserves.
The following cases were examined:
1. Natural depletion with Flowing well pressure limit of 100bars
2. Natural depletion up to a reservoir pressure 290bars then introduction of
Water injection as secondary recovery process
3. Natural depletion to a reservoir pressure 350bars then introduction of Gas
injection as secondary recovery process
4. Natural depletion to a reservoir pressure 350bars then introduction of
Water injection as secondary recovery process for 4years followed by an alternate
gas injection.
1.3 Geological Description And Field Characteristics
In a bid to explore the Alwyn North field a thorough geological description of the
field is necessary to ensure complete understanding of the geology of the area. The
geological settings, sedimentology and other related aspects of the field are
described in this section.
NWOSU, DIXON 12 IJEH, ISIJOKELU
1.3.1 Location
The Alwyn North Field was discovered in 1974 in the South Eastern part of the East
Shetland Basin in the UK North sea, about 140 km East of the near most Shetland
Island and about 400 km North East of Aberdeen. The Alwyn field lies respectively
4 and 10 km south of Strathspey and Brent field, 7 km east of Ninian field, and 10
km north of Dunbar field (see field localisation map below). The water depth is
around 130 m. The field is in the UKCS Block 3/9 and extends northward into the
Block 3/4. The location map and 3D view of the area is shown in Fig. 1.1 and 1.2
respectively.
Figure1.1: Alwyn North Field Localization Map
NWOSU, DIXON 13 IJEH, ISIJOKELU
Figure 1.2: Alwyn Area Location Map
1.3.2 Field Characteristics Tectonics
Tectonics played a significant role on the structure of ALWYN North field.
Tensional movements leading to the development of the Viking Graben from
the lower Permian times to Upper Jurassic generated a complex fault pattern.
Several seismic data acquisition programs were carried out: 2D seismic in 1974
and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing
sands are controlled on one hand by normal sealing faults with a general North-
South direction, on the other hand by a major unconformity at the base of
Cretaceous. This unconformity is related to erosion of the Brent formation in the
eastern part of ALWYN North field.
In a bid to explore the Alwyn North field a thorough geological description of
the field is necessary to ensure complete understanding of the geology of the
area. The geological setting, sedimentology and other related aspects of the field
are described in this section.
1.3.3 Geological Setting
The Brent formation was deposited in a deltaic and shallow marine environment
NWOSU, DIXON 14 IJEH, ISIJOKELU
during the Middle Jurassic period. The Statfjord formation was deposited in a
fluvial and shallow marine environment during the Lower Jurassic period. Each
panel has several pre-cretaceous tilted blocks (see Figure 1.3 below). The cap
rock is made of three on lapping shaly formations:
Heather formation: marine transgressive shales with thin limestone
stringers, which is deposited after the tectonic activity.
Kimmeridge clay thick in the West, thin in the East, which is the main
hydrocarbon source rock.
Thick cretaceous sequence.
Figure1.3: Stratigraphy of the Alwyn North Field
ALWYN North reservoirs were relatively unaffected by diagenesis due probably
to an early hydrocarbon impregnation.
RFT shows that each panel had its own pressure regime. Water-oil contacts were
identified at different depth. All the panels were independent from the other.
NWOSU, DIXON 15 IJEH, ISIJOKELU
1.3.4 Brent East Reservoir of Alwyn North Field
This study was considering only the East Panel of the Alwyn North field.
1.3.4.1 Geological Description
The structure of Alwyn Brent East Block was generally an eroded monoclinal,
with Base Cretaceous Unconformity (BCU) setting east and south limit, Spinal
Fault setting west limit (separating Brent east from north and central west
blocks), and a fault with sometimes very small throw setting north limit. East
structure under BCU is quite complicated, and described under the generic term
of slumps (linked to gravitational collapse of head blocks during Cretaceous
erosion similar as ones encountered in Brent field).
In the Brent East panel, the oil zone is in a stratigraphic trap as shown below
created by the erosion unconformity to the east, by a northsouth fault to the
west (between A-1 and A-2 wells) and by a transverse fault to the north. The
Brent Geological Cross section is shown below.
Figure 1.4: Brent Geological Cross section
The Brent geological well section is shown in Fig. 1.5.
NWOSU, DIXON 16 IJEH, ISIJOKELU
Fig: Brent Geological well Section
1.3.4.2 Tectonics
Several seismic data acquisition programs were carried out: 2D seismic in 1974
and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing
sands are controlled on one hand by normal sealing faults with a general North-
South direction, on the other hand by a major unconformity at the base of
Cretaceous. This unconformity is related to erosion of the Brent formation in the
eastern part of ALWYN North field.
Following the seismic interpretation, ALWYN North field was divided into the
following panels:
Brent North.
Brent Northwest.
Brent Southwest.
Brent East.
Statfjord
Triassic .
NWOSU, DIXON 17 IJEH, ISIJOKELU
The first four panels are oil bearing within the Brent. The Statfjord formation is
a condensate gas reservoir with the Brent completely eroded. The underlying
Triassic is gas bearing.
Figure 1.6: Cross Section Through Alywn Showing The Faults
1.3.4.3 Sedimentology
The Brent group is divided into three main units: the Lower Brent (Broom,
Rannoch and Etive formations), the Middle Brent (Ness formations), and the
Upper Brent (Tarbert formations). The last two are the only oil-bearing
formations in the Brent East panel.
The Lower Brent formation was deposited in a shoreface (Rannoch) to
coastal barrier (Etive) environment. The clastic reservoir is made of
transgressive sandstone (Broom) and prograding sandstones (Rannoch
and Etive). Thus, the petrophysical properties range from low to medium
permeability. This unit does not contain any oil in the Brent East reservoir.
The Middle Brent formation was deposited in a deltaic to alluvial plain
(Ness 1) and lagoon to lower delta plain (Ness 2) environment. Thus,
sandstones are inter bedded with clay and coal. In general, Ness 1 unit has
NWOSU, DIXON 18 IJEH, ISIJOKELU
poorer petrophysical characteristics than Ness 2 unit and its oil-bearing
leg is much lower especially to the East of the reservoir.
The Upper Brent was deposited in a prograding lower shoreface
environment. Three different types of sandstone are identified. At the top
(Tarbert 3), are massive sands with very good reservoir characteristics.
This is the main oil bearing unit in the Brent East reservoir. Below
(Tarbert 2), there are mica-rich sandstone with lower permeability. These
mica-rich sandstones exhibit a high natural radioactivity. The base of the
Tarbert formation (Tarbert 1) is very similar to the top sandstone. Despite
its lower average permeability, Tarbert 2 unit is not considered as a
permeability barrier.
Figure 1.7: Depositional Setting of the Brent Group
To summarize, Tarbet can be described as massive shore face sands with
excellent petro-physical properties, well connected throughout the field and
may be even regionally, communicating partially with Upper Ness fluviatile
system which is isolated from Lower Ness.
Base Brent Etive and Rannoch are better quality reservoirs, but mainly water
bearing in Brent East Block.
NWOSU, DIXON 19 IJEH, ISIJOKELU
Considering the small oil content in Ness 1, this unit is neglected in the reservoir
model. Thus, the reservoir model focuses on the Ness 2 and Tarbert 1, 2 and 3
units.
The Brent East reservoir of Alwyn North was characterized using data from two
of the original vertical appraisal wells (3/9A-2, 3/9A-4) and two new deviated
delineation wells (N1 and N3). N3 characterized the northern part of the field
where an important oil leg was confirmed mainly in the Tarbert units. N1
located to the West did not produce any oil and only encountered the aquifer,
which does seem to be active. The water salinity in the reservoir is about 17,000
ppm.
1.3.4.4 Log correlations
The last two appraisal wells, namely N1 and N3, were extensively cored.
Numerous core samples were analyzed through routine conventional core
analysis. Several permeability-porosity relationships were derived (see annex 2):
one for each of the reservoir units considered (Tarbert 3, Tarbert 1&2 and Ness 2).
Special core analyses were carried out on a few samples from each of the
reservoir units. Unsteady state measurements under reservoir conditions (fluids
and pore pressure) were conducted to obtain a set of relative permeability and
of capillary pressure curves.
NWOSU, DIXON 20 IJEH, ISIJOKELU
Figure 1.8: Showing Log Correlations
1.4 OBJECTIVES OF THE STUDY
The goal of this study is to propose an initial development plan for the Brent
East reservoir, this plan should maximize the total hydrocarbon production and
minimize the development cost in $/bbl.
Several aspects were investigated:
a. Using available data, a reservoir performance analysis was performed to
identify the main reservoir driving force. Using material balance, the different
drive mechanisms were investigated in order to estimate the oil recovery.
Primary production as well as secondary production must be investigated
(material balance calculation above Psat). In order to calculate the Material
Balance, use average values of Swi and Sor.
b. Based on the results of the first step, different production schemes should
were defined: Natural depletion, water injection, gas injection. Each scenario
was reported in detail with all relevant information, assumptions and selected
NWOSU, DIXON 21 IJEH, ISIJOKELU
options. The annual production plateau was estimated to be around 15% of
EUR. The production profiles were evaluated over 15 years.
c. 60% of EUR must be produced at plateau rate.
d. Each scenario was implemented in the numerical reservoir model. In natural
depletion, the model was run until 100 bar (BHP). Are the calculated
numbers of producers relevant? Investigate was done to give the best number
of wells. For secondary production: We optimize the injectors to meet the
target production. Attention was paid to the critical gas saturation (Sgc).
e. A proposed scenario was selected based on technical criteria and economic
parameters were compared.
f. Using the selected development scheme, the major uncertainties were
investigated to assess the impact of the model assumptions including for
instance:
permeability anisotropy: Ky = 10*Kx,
fault transmissibility: sealing / non sealing,
Tarbert 2 Tarbert 3 connection: transmissivity of layer 4,
aquifer strength: decrease of pore volume in the water zone (see the impact
on natural depletion scheme),
1.5 Reservoir Model And Characteristics
Based on the Brent East characteristics described previously, a reservoir
simulation model was designed to investigate the production capacity of this
reservoir. The reservoir model was built using the four appraisal wells: A2, A4,
N2 and N3. These wells can be abandoned according to the production scheme.
Due to a sketchy knowledge of the Brent East reservoir at the beginning of the
study, a Black Oil model was designed with rectangular cells with 36 cells along
the x-direction and 51 cells along the y-direction. The geometry definition is
NWOSU, DIXON 22 IJEH, ISIJOKELU
given in a Petrel file: 'MODEL_PETREL.GRDECL'. The structural
framework used for the Corner Point Geometry is based on the Spinal Fault
Geometry and the North fault limit. Model size is geometrically 36x51x18 but is
in reality 36x51x17 (since the 1st layer representing all layers between the Base
Cretaceous Unconformity and Top Brent is killed by nil porosity), Fig. 1.8.
1.5.1 Rock Typing
The rock typing to represent the Tarbert and Ness formations as shown in Table
1-1. Tarbert can be described as massive shore-face sands with excellent
petrophysical properties, well connected throughout the field. Tarbert
communicates partially with the Upper Ness fluviatile system which is isolated
from Lower Ness.
Ness 1 and Ness 2 bear small oil content while lower Brent is mainly water and
are thereby neglected in the reservoir model. Thus, the reservoir model focuses
on Tarbert 1, 2 and 3.
Table 1.1: Rock Typing and Layers representing the Tarbert and Ness
Rock Type Formation Layer Tags
Rock Type Formation Layer Tags
Impermeable zone
1
Type 1
Tarbert 3
2,3,4
Tarbert 2
5,6
Tarbert 1
7,8,9
Type 2
Type 2
Ness 2
10,11,12,13,14
Ness 1
15,16
Lower Brent
17,18
This model will only include the oil bearing sands from the Tarbert (1, 2 &
3) and Ness (1 & 2) formations. Thus, in this study, the reservoir model has 17
layers:
3 in Tarbert 3
2 in Tarbert 2
NWOSU, DIXON 23 IJEH, ISIJOKELU
3 in Tarbert 1
5 in Ness 2
4 in Ness 1
There are three equilibration regions defined in the EQUNUM keyword in the
Regions section. However, there is no evidence of compartmentalization, all the
regions have the same water-oil contact (WOC) and pressure regime.
Figure 1.8: Reservoir Model Showing the Grids
Initial pressure of the reservoir is 446 bar and saturation pressure is 258 bar. The
reservoir petro- physical properties (porosity, permeability) were also scaled up.
The property modeling was done as follows:
Tarbert and Ness shallow marine sheet flood sandstone: Determine
modelling with trend surface control maps
Ness: Object modelling floodplain & lagoonal back barrier lobes
Porosity: Depth and facies trends incorporated
Permeability: Calibrated with core and DST Data
NWOSU, DIXON 24 IJEH, ISIJOKELU
The petrophysical properties (porosity, permeabilities and NTG) are included in
the grid in the include file: 'MODEL_PETREL_PETRO.GRDECL'. The original
oil in place (OOIP) estimation, according to the geological model, is about 35.68
MMsm3; this value is dependent on capillary pressure.
1.5.2 Reservoir Fluid Properties
Black Oil PVT representation was used in this study. The PVT data file PVT.INC
contains the relevant composite black oil PVT data which accounts for the field
separation conditions. Below is a table showing the initial PVT values of the
reservoir fluid.
Table 1.2: Initial Values of Fluid Properties
Properties Value
Initial Reservoir Pressure (Pi) 446 Bar
Temperature (T) 110 oC
Saturation Pressure (Psat) 258 Bar
GOR 206.8974 v/v
Formation factor, Bo@ Pi 1.6038
OOIIP 35.68MMm3
1.5.3 Fluids in Place
The original data file was initialized to obtain the fluid in place values shown
below. This was illustrated by adding the ECHO and FIPNUM keywords in the
dot DATA simulation.
NWOSU, DIXON 25 IJEH, ISIJOKELU
Table 1.3: Table Showing the Fluids in Place Volume
Currently in place Tarbert Ness Entire Field
Oil (sm3) 31,104,045 4,577,946 35,681,991
Water (sm3) 125,222,389 188,540,747 313,763,137
Dissolved Gas
(sm3)
6,426,769,976 945,920,886 7,372,672,862
Figure 1.9: Data File Initialized to Obtain Volumes In-Place
NWOSU, DIXON 26 IJEH, ISIJOKELU
As shown above, the Tarbert (Region 1) had Oil Originally in place as 31104045
Sm3, while Ness (region 2) had Oil Originally in place as 4577946 Sm3,with
Tarbert contributing 87% of the total oil in place in the entire field. The Ness
can be said to be non-prolific, since it is producing more water than oil. For this
reason, region 2 will not contribute per say to our proposed production, as such
drilling into it would lead to early breakthrough and a reduction in oil recovery.
Hence, our study was focused mainly on the Tarbert rock.
NWOSU, DIXON 27 IJEH, ISIJOKELU
CHAPTER TWO
FIELD DEVELOPMENT TECHNIQUES
In this chapter we proposed an initial development plan for the Brent East
reservoir, this plan should maximize the total hydrocarbon production and
minimize the development cost in $/bbl. This is done in two parts, the analytical
calculation of the recovery from natural depletion, water injection and gas
injection and the other part, the simulation using ECLIPSE for each of the above
mentioned scenarios with the inclusion of water alternate gas injection. In the
excel calculation involving material balance and the different drive mechanisms
were used to estimate the oil recovery. The first case used to produce the oil in
place was natural depletion and also different cases of secondary production
were also investigated (material balance calculation above Psat).
The different secondary production schemes used were: Natural depletion, water
injection, gas injection as well as Simultaneous Water Gas Injection (WAG).
Each case is described in this chapter using both excel calculation and eclipse to
validate. The annual production plateau estimate is around 15% of EUR. The
production profiles were evaluated over a period of 15 years.
Each case was implemented in the numerical reservoir model. For primary
method, production was optimized by investigating the best number of wells.
For secondary method, production was optimized by investigating the best
number of producers and injectors to meet the target production.
2.1 Constraints
2.1.1 Drilling Constraints
To develop the Brent East reservoir, a 40-slot well platform will be used.
The maximum well deviation should not exceed 46 with respect to
vertical.
Production program should start at the beginning of 2012.
NWOSU, DIXON 28 IJEH, ISIJOKELU
The maximum horizontal drain (x or y direction) of a well will be less than
1000 m.
The kick off point (start of deviation) is set at 2,000 m ground level. It is
also possible to drill vertical wells with subsea completion.
The average drilling completion time is about 2 months for vertical wells
and 2 months for the horizontal ones.
Wells may be t
Two drilling rigs are available.
The wells are drilled in 7".
2.1.2 Production Constraint
The minimum bottom hole flowing pressure (BHFP) is 260 bar.
The perforations of the wells are chosen to optimize recovery depending
on the well location.
Vertical well production test indicates a maximum fluid (oil + water) rate
of 1,800 Sm3/d.
Horizontal well could produce up to 2,400 Sm3/d of liquid. Only flowing
production is considered at this stage.
Drainage radius for vertical wells is about 400 m.
The averaged maintenance down time is 10 % for all the wells.
Due to surface facilities on platforms, the maximum allowable GOR is 1500
m3/m3 and the maximum allowable water cut is 90 %.
The minimum economical rate for the field is 1000 Sm3/d of oil.
To estimate the productivity index, we considered a skin of 5
The annual production plateau should be around 15% of EUR (~7200
Sm3/d)
The production plateau should be maintained for 60% of the total oil
production
The production profiles should be evaluated over 15 years
2.1.3 Water Injection Constraint
During secondary recovery, the following constraint will be considered for water
injection.
NWOSU, DIXON 29 IJEH, ISIJOKELU
Seawater may be injected into the reservoir without any water
compatibility problem.
To estimate the water injectivity index, we considered a skin of -4 induced
by thermal fractures due to the low temperature of the sea water injected
in the formation (surface temperature of water: 8C).
The fracture pressure of the Brent reservoir is about 480 bars.
The maximum water injection rate is 3,000 Sm3/d. The maximum total
water injection available is 15,000 Sm3/d.
Control in voidage replacement
2.1.4 Gas Injection Constraint
If gas injection is considered during secondary recovery, the following constraint
will be considered:
Lean Statfjord gas may be injected.
This lean gas is assumed to have the same characteristics as the Brent dissolved
gas.
The maximum gas injection rate is 800,000 Sm3/d per well. The maximum total
gas injection available is 3,200,000 Sm3/d.
Control in voidage replacement.
2.2 Analytical Calculations
The main drive mechanism for production of the Alwyn North Brent East
reservoir is Expansion of original reservoir fluids (Oil) because the reservoir
initially is undersaturated and will be depleted above bubble point pressure with
a minimum drawdown of 20 bars. However, secondary and enhanced oil
recovery mechanisms will also be deployed to increase recovery via water and/or
gas injection. These scenarios will be investigated using MBE (Analytical or
Hand Calculations) vis--vis dynamic Numerical Simulation with Eclipse and
the results will be presented and discussed.
However, before proceeding we ran Eclipse in NOSIM mode to generate the
PRT file containing the STOIIP of Alwyns Tarbert and Ness formations. The
following screenshot captures this information and other important data.
NWOSU, DIXON 30 IJEH, ISIJOKELU
The PVT file used for various calculations is shown below. The full PVT file used
for gas injection is shown in the appendix.
Table 2.1: PVT File
Assumptions
1. The Petro-physical and PVT Properties of both rock types are assumed to be
similar.
2. Vertical Sweep Efficiency, Ev is assumed to be 0.7 for all regions.
2.2.1 Case One: Natural Depletion
This refers to production of hydrocarbons from a reservoir without the use of
any process (such as fluid injection) to supplement the natural energy of the
reservoir. In the case of natural depletion, we used the material balance equation
(MBE) to calculate the production and ultimate oil recovery under a natural
NWOSU, DIXON 31 IJEH, ISIJOKELU
depletion process. The reservoir was depleted from the initial pressure (Pinitial =
258bar) to a bottom hole pressure limit of 100 bar.
The data used for these calculations were obtained from the PVT report and the
INPUT data file. The Original Oil in Place for the two regions (Tarbert and Ness)
was obtained from an initialization run in ECLIPSE. The result is displayed in
Figure 1.9.
In this type of reservoir, the principal source of energy is a result of gas
liberation from the crude oil and the subsequent expansion of the solution gas
as the reservoir pressure is reduced.
Assumptions:
1. No Aquifer support or water influx into the reservoir
2. Recovery is by rock and liquid expansion
2.2.1.1 Minimum number of wells
The following equations were used to determine the minimum number of wells:
------------------------------2.1
To get the initial number of wells, we need:
--------------------------------------2.2
Considering that for the development field case we don't have any production
data, to estimate productivity index (average value between Pi and Pmin):
--------------------------------------------------2.3
Where,
= 0.0086.2 = 0.0536 ___metric units
= 0.0086.2 = 0.0536 ___metric units
At reservoir pressure, 446bars
NWOSU, DIXON 32 IJEH, ISIJOKELU
At 280bars,
Well Potential =
----------------------------------------------2.4
Assuming EUR = 25%
Hence,
Minimum number of wells =
2.2.1.2 Material Balance For Natural Depletion Alone
a. Rock And Fluid Expansion
The equations were used for calculating material balance;
---------------------------------------------------------------2.5
Where,
Np = Cumulative Oil Produced
Boi = Initial Formation Volume Factor of Oil
Bo = Final Formation Volume Factor of Oil
N = Stock Tank Oil Initially in Place (STOIIP)
Ce = Equivalent Compressibility of Oil
P = Pressure Drop
But,
----------------------------------------------------2.6
Where,
Co = Compressibility of Oil
Cw = Compressibility of Water
NWOSU, DIXON 33 IJEH, ISIJOKELU
So = Oil Saturation
Swc = Connate Water Saturation
Cf = Rock Compressibility
Also
-----------------------------------------------------------------------------2.7
i. Tarbert Region:
Boi = Bo @ 446 = 1.6038
Bo @ 280 = 1.6737
For water participating in expansion,
-----------------------------------------------------------------------2.8
ii. Ness Region:
Boi = Bo @ 446 = 1.6038
Bo @ 280 = 1.6737
NWOSU, DIXON 34 IJEH, ISIJOKELU
For water participating in expansion,
Estimation of the above parameters and final EUR for NATURAL DEPLETION
case are presented below:
Table 2.2: Analytical solution for Recovery by Natural Depletion Drive
NWOSU, DIXON 35 IJEH, ISIJOKELU
2.2.2 Case Two: Water Injection
The previous case assumed the reservoir produced only by natural depletion. In
practice, reservoirs are rarely allowed to deplete almost to their bubble point
pressures. Pressure maintenance schemes are implemented to sustain plateau
production usually with Water Injection Scheme (Note: Pressure maintenance
by Gas Injection is usually not feasible because of the enormous amounts of gas
that is required; gas Injection supports oil recovery mainly via dissolution and
miscibility phenomena).
Here, we will calculate the amount of additional oil that can be recovered by
water injection and also the number of wells that will effectively sweep oil in the
reservoir while maintaining the reservoir pressure above bubble point.
The total recovery during a water injection process can be given by;
----------------------------------------------------------------2.9
-------------------------------------------2.10
Where,
Ed = f(primary depletion, krw & kro, o & w)
Ea = f(mobility ratio, pattern, directional permeability, pressure
distribution, cumulative injection & operations)
Ev = f(rock property variation between different flow units,fluid density), Ev =
0.7(assumption)
2.2.2.1 Material Balance
i. Tarbert Region:
Evaluation of Ea
Ea can be gotten from the graph as shown below:
NWOSU, DIXON 36 IJEH, ISIJOKELU
Fig2.1: Reciprocal Mobility Ratio Chart
The Mobility Ratio (MR) is first obtained using the relationship
---------------------------------------------------------2.11
Next, the Reciprocal Mobility Ratio (inverse of MR) is calculated and the areal
sweep efficiency (EA) corresponding to this value is read off the Reciprocal
Mobility Ratio Chart.
NWOSU, DIXON 37 IJEH, ISIJOKELU
Table 2.3: Reciprocal Mobility Ratio computation for obtaining error. Ea
From the table and chart above, Ea = 0.98
Evaluation of Ed
Ed is calculated from a plot of fractional flow, fw versus water saturation, Sw.
This plot shows the fractional flow of water when injected into the reservoir to
displace oil. The plots are different for each rock type.
-------------------------------------------------------------2.12
Plot of fw vs Sw is generated using corresponding Relative Permeability
(Imbibition) data
Table 2.4: Relative Permeability (Imbibition) data table
NWOSU, DIXON 38 IJEH, ISIJOKELU
Fig2.2: Fractional Flow curve for the Tarbert Region
As shown above,
Swc = 0.15, Swm = 0.71
Therefore, the drainage efficiency at Break-through (BT) is obtained from
equation 2.12;
Recovery =
= 0.6588 = 65%
Ed = 0.66, Ev = 0.7, Ea = 0.98
Therefore, R = 0.66*0.7*0.98 = 0.45
ii. Ness Region
Evaluation of Ea
EA is the same as obtained for Tarbert since both rock types contain the same
reservoir fluid.
Evaluation of Ed:
Plot of fw vs Sw is generated using corresponding Relative Permeability
(Imbibition) data
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
1.1
0 0.2 0.4 0.6 0.8 1 1.2
fw
Sw
Tarbert
Tarbert
Swm
NWOSU, DIXON 39 IJEH, ISIJOKELU
Table 2.5: Relative Permeability (Imbibition) data table
Fig2.3 : Fractional Flow curve for the Ness Region
As shown above,
Swc = 0.30, Swm = 0.66
Therefore, the drainage efficiency at Break-through (BT) is obtained from
equation 2.12;
Recovery = (0.66-0.30)/(1-0.30) = 0.51 = 51%
Swm
NWOSU, DIXON 40 IJEH, ISIJOKELU
Ed = 0.51, Ev = 0.7, Ea = 0.98,
R = 0.51*0.7*0.98 = 0.35
2.2.2.2 Estimation of Oil Recovery Using Hand Calculation
From equation 2.9,
Oil Recovery with water:
Total oil produced:
------------------------2.13
Therefore,
Table 2.6 shows a section of an MS Excel file that contains calculations for the
total oil that can be produced by water injection.
NWOSU, DIXON 41 IJEH, ISIJOKELU
Table 2.6: Oil Recovery from Natural Depletion and Water Injection
From the table above, the total oil recovery from Tarbert and Ness by natural
depletion and water injection is 4.49E+06 Sm3 with a Global percent recovery of
51%.
Given that annual production plateau should be around 15% of Estimated
Ultimate Reserves (EUR), Average Oil Withdrawal per day calculated from Table
2.6 is 7478 Sm3/day.
2.2.2.3 Minimum number of wells:
Oil Flow rate, Qo, per well, is given by :
----------------------------------------------------------2.14
Where,
Kro = relative permeability of oil in the presence of water
Bo = oil formation volume factor
o = viscosity of oil
NWOSU, DIXON 42 IJEH, ISIJOKELU
C =conversion factor
K = permeability
H = net pay thickness
P = pressure drawdown
Rd = reservoir drainage radius
Rw = well radius
S = skin
Assumptions for Calculation:
Wells drilled and completed in the TARBERT Region
Reservoir producing at Pseudo-steady state
Oil flowing at connate water saturation
Reservoir drainage radius equals 400m
Values of average permeability, K, Net-to-Gross ratio, NTG and average
thickness, DZ were obtained from the geological model using FLOVIZ with
Eclipse Simulator run on NOSIM mode. An examination of the 9 vertical
layers of the Tarbert region showed an erosion of the top layer. Hence, only 8
layers of reservoir sand thickness were used.
Qo @ 446bars
Bo = 1.6038
o = 0.3916
Kro = 0.8
Z = 8.0907 per layer* 8 layers *NTG = 64.7256 * 0.96883 = 62.7081m
Qo @ 280bars
Bo = 1.6737
o = 0.2829
Kro = 0.8
NWOSU, DIXON 43 IJEH, ISIJOKELU
Z = 8.0907 per layer* 8 layers *NTG = 64.7256 * 0.96883 = 62.7081m
We have been informed of a possible production downtime of 10%. Hence, our
rate is subject to a WEFAC (Well Efficiency Factor) of 90%.
Therefore,
=
Implication:
We need to drill at least 5 producer wells for optimal reservoir exploitation by
Natural Depletion.
Secondary oil recovery by water injection is usually incorporated in the field life
of a reservoir. Hence, optimum number of wells for increased recovery by water
injection was also calculated. Because of thermal cracks induced by injecting
cold North Sea water into the hot reservoir, a skin of -4 is expected for a water
injection case.
The most efficient way to determine the amount of Water for injection is to
calculate the amount of water required to achieve zero-net-voidage by applying
the VOIDAGE REPLACEMENT PRINCIPLE.
Field oil production rate was previously determined as 7478 Sm3/day. We shall
find the equivalent reservoir oil volume. This volume is equal to reservoir water
volume for zero-net-voidage.
Subsequently, we determine the surface equivalent of this reservoir water which
is calculated as:
NWOSU, DIXON 44 IJEH, ISIJOKELU
Implication:
We need to drill at least 4 injection wells for optimal reservoir exploitation by
voidage replacement.
2.2.3 Case Three: Gas Injection
We would calculate the amount of recovery that can be achieved by gas
injection while maintaining the reservoir pressure above bubble point. Because
the NESS region is predominantly water zone, there will be no need injecting gas
in this region. Hence, we focused on recoveries from the TARBERT region.
2.2.3.1 Material Balance
i. Tarbert Region
The total recovery possible during a gas injection process can be obtained from
equation 2.15
---------------------------------------------------------------2.15
Recall that Equation 2.10 for Recovery Factor with all parameters defined as
previously is:
Evaluation of EA:
The Mobility Ratio is first obtained, Reciprocal Mobility ratio estimated, and
traced up to the corresponding gas cut curve to read off EA =0.74 (See Table
2.8).
Evaluation of ED:
As with the water injection case, plot varies for the different rock types as
presented below. Because the reservoir is predominantly water-wet, Gas
NWOSU, DIXON 45 IJEH, ISIJOKELU
Injection constitutes a Drainage Process. Hence, the Drainage Data for Tarbert
is made use of for computing fractional flow.
Table 2.7: Gas-Oil Relative Permeability Data for Rock-Type 1
NWOSU, DIXON 46 IJEH, ISIJOKELU
Figure 2.4: Relative permeability versus gas saturation curves
NWOSU, DIXON 47 IJEH, ISIJOKELU
Figure 2.5: Plot of Gas Fractional flow against saturation for Tarbert
From the graph, the Sgf and Sgm as shown on the chart are determined.
Sgm = 0.25 , Sgc 0.0
Therefore, the drainage efficiency at Break-through (BT) is obtained as follows;
EV = 0.7 (assumption)
Applying Equation 2.10,
Recovery of oil from gas injection is shown in the Table 2.8 below:
NWOSU, DIXON 48 IJEH, ISIJOKELU
Table 2.7: Recoveries from combined Natural Depletion and Gas Injection
As shown in the table above, total oil produced from Tarbert due to gas injection
is 5,219,682.323 Sm3 with a per cent recovery of 14.49 %.
Total oil from Tarbert from both natural depletion and gas injection is therefore,
6,978,338.529 Sm3 with a per cent recovery of 19 %.
NWOSU, DIXON 49 IJEH, ISIJOKELU
CHAPTER THREE
DYNAMIC FIELD DEVELOPMENT STUDY USING ECLIPSE
SOFTWARE
A field development study can be conveniently done using Eclipse as different
reservoir production cases can be simulated to determine the best strategy for
producing from the field.
Four cases will be considered:
Natural Depletion
Natural Depletion followed by Water Injection
Natural Depletion Followed by Gas Injection
Natural Depletion followed by Water Alternating Gas Injection (WAG)
3.1 Case One: Natural Depletion
Natural depletion, also known as primary production, describes a scenario
where the reservoir is produced via its natural energy. In natural depletion, the
energy required to drive the fluids from the reservoir to the wellbore and
consequently to the surface is the reservoirs energy. This energy might be due
to a solution gas drive, aquifer and rock expansion, gravity drainage or water
drive.
3.1.1 Natural Depletion with the Available Four Exploratory Wells
For this natural depletion case, the original four vertical wells in the model were
run to limit BHP of 100 bars atmospheric and the evolution of field pressures
and flow rates during the period were noted.
NWOSU, DIXON 50 IJEH, ISIJOKELU
Fig 3.1: Well Architecture: Natural Depletion from Wells PA2, PN2, PA1 and
PN1
Fig 3.2: FOPR, FOPT and FOE as a function of time for th e 4-well Natural
Depletion case
NWOSU, DIXON 51 IJEH, ISIJOKELU
The figure above indicates a maximum oil recovery of 22% for this natural
depletion case. Also, the plateau production period peaks for only five years and
then declines to zero in seven years. Hence, natural depletion can neither
sustain production for the 15 years proposed for the project nor can recoveries
are maximized.
Moreover, the principle of profitable business is directly challenged as oil
production revenue will be insufficient to offset the huge investments required
for a project of this magnitude.Thus, the need for secondary and tertiary
recovery schemes arises as the field cannot be produced with a primary recovery
technique alone.
Further, a disparity was observed between the calculated and simulated value of
the maximum recovery. The recovery from the analytical calculations was 6%
while the recovery from the numerical simulation was 22%. This suggests that
there is a nearby aquifer that provided pressure support to the reservoir
Fig 3.3: Oil Production Rate as a Function of Time from Wells PA2, PA1, PN2
and PN1
From an analysis of the figure above, it was observed that well PA2 contributed
poorly to the total field production. This could be due to any or a combination
of the following reasons:
NWOSU, DIXON 52 IJEH, ISIJOKELU
Improper well placement,
Proximity to a fault,
High positive skin
Completing the well in a water zone.
Well PA2 can either be shut off or converted into an injection well since it is a
poor producer. The latter was deemed a better economic decision as it ensured
the continuous use of the well to add value to the field. Hence, subsequent
simulations for the natural depletion case were done with PA2 shut while new
wells were drilled and brought on stream.
3.1.2 Effect of Critical Gas Saturation
To study the effect of critical gas saturation on field productivity, the critical gas
saturation was increased from 0%, as was used in the previous cases, to 10%. The
implication of setting the critical gas saturation to 0% is that gas begins to
evolve from solution throughout the reservoir as soon as the reservoir pressure
depletes to a level that is below the bubble point pressure of the oil. This leads
to an increase in gas-oil ration and a subsequent decrease in oil productivity.
Fig 3.4: Comparing the Field Recovery Efficiency and Field Plateau
Production Rate for both cases
NWOSU, DIXON 53 IJEH, ISIJOKELU
Higher recoveries and longer plateaus were recorded for the simulation case
with a critical gas saturation of 10%. There was an increase in total recovery from
22% to 26% and the time required for production to terminate increased by one
year.
Fig 3.5: Comparing the Field Pressure and Total Field Production Volume for
both cases
By increasing the critical gas saturation to 10%, the field total production
increased from 8MMm3 to 9MMm3 and an additional year was required for the
reservoir to deplete to the bottom hole flowing pressure limit of 100bars.
As with the previous graphs, the new case gave better results. In contrast with
the previous case, an extra year was required for the field water cut to attain its
maximum value and an additional 18 months was required for the field gas-oil
ratio to attain its peak. From the results above, it can be confidently inferred
that recovery is improved when dissolved gases stay longer in solution as gas
mobility is delayed to obtain better oil recoveries. Hence, subsequent simulation
cases will be done with the critical gas saturation set to 10%.
NWOSU, DIXON 54 IJEH, ISIJOKELU
Fig 3.6: Comparing the Field Water Cut and Field Gas-Oil Ratio for both
cases
3.1.3 Natural Depletion with Increased Development Wells:
The need to drill added development wells arises as a result of the fact that the
three available wells are inadequate to optimally drain the field of its oil
resources. Economics plays a major role here as drilling of new wells represents a
major portion of capital expenditures. Thus, the number of new wells to be
drilled should be optimized to obtain maximal recovery from the field.
3.1.3.1 Natural Depletion with Five Producer Wells
The minimum number of production wells, as computed through the hand
calculations, was 5 wells. Well PA2 was shut in and two new wells, PB1 and PB2,
were drilled to increase recovery from the field. PB2 was drilled very close to the
shut-in PB1 and PB1 was drilled in an area with very high oil saturation.
NWOSU, DIXON 55 IJEH, ISIJOKELU
Fig 3.7: Well Architecture: Natural Depletion with W ells PA1, PNI, PN2, PB2
and PA4
Fig 3.8: Natural Depletion with 5 Producers: FOE, FOPT and FOPR as a
function of time
For the 5-well case, FOPR peaked for 6 years in contrast with the 4-well case in
which FOPR peaked for only 5 years. Field Oil Recovery also increased from 26%
to 30%.
NWOSU, DIXON 56 IJEH, ISIJOKELU
Fig 3.9: Natural Depletion with 5 Producers: FPR, FOE, F WCT, FGOR as a
function of time
Fig 3.10: Well by Well Analysis: Individual Oil Well Production Rate as a
function of time
NWOSU, DIXON 57 IJEH, ISIJOKELU
3.1.4 Inferences: Natural Depletion
From the simulations and optimizations done thus, we came up with the
following inferences:
Ultimate Oil Recovery:
The oil recovery obtained from the different simulation runs is shown on
the bar chart displayed above. EUR from the natural depletion varied from 20%
to about 30%. The highest recovery (30%) was obtained by depleting the
reservoir naturally with 7 wells while shutting well A2. The low recovery from
this type of reservoirs suggests that large quantities of oil remain in the reservoir
and the reservoir pressure dropped very much for this low recovery. This
naturally depleted reservoir will be considered a good candidate for secondary
recovery applications such as water injection as well as gas.
Reservoir pressure:
The reservoir pressure declined rapidly and continuously. This reservoir
pressure behaviour is attributed to the fact that no extraneous fluids or gas caps
are available to provide a replacement of the gas and oil withdrawals. There is
no voidage replacement no sweep provision for the hydrocarbon.
Water production:
There was considerable water production with the oil during the entire
producing life of the reservoir. This is due to the presence of an active water
drive.
Gas-oil ratio:
This natural depletion is characterized by a rapidly increasing gas-oil ratio from
all the wells, regardless of their structural position. After the reservoir pressure
has been reduced below the bubble-point pressure, gas evolves from solution
throughout the reservoir. Once the gas saturation exceeds the critical gas
saturation, free gas begins to flow toward the wellbore and gas-oil ratio
increases.
NWOSU, DIXON 58 IJEH, ISIJOKELU
3.2: Case 2: Water Injection Preceded by Natural Depletion
In many cases, water injection has traditionally used in the oil industry for
pressure maintenance. It is usually used to maintain pressure above the bubble
point pressure and in some cases, to pressurize the reservoir to the bubble point
pressure. By simulation for water injection, water is pumped or injected into the
reservoir to maintain pressure and expel oil in the pore spaces. This water
displaces this resident oil and pushes them towards the producing wells in that
manner so as to maintain pressure and achieve improved recovery.
In this water injection simulation case, the desire was to maintain the average
reservoir pressure at 290 bars. Hence, the field was naturally depleted from 490
bars to 290 bars and water injection was initiated at this instance. Well PA2, the
poor producer well, was converted to an injector well. Four additional wells were
then drilled to serve as injection wells.
Due to the fact that oil could be recovered as a result of the water injection
sweep, two extra producer wells were drilled. This gave a total of 7 producers
and five injector wells.
NWOSU, DIXON 59 IJEH, ISIJOKELU
Fig 3.11: Well Architecture: 7 producers and 5 injectors. We ll PA2 is an
injection well
NWOSU, DIXON 60 IJEH, ISIJOKELU
Fig 3.12: Water Injection: FOPR, FOE and FOPT as a function of time
As predicted, the recovery efficiency increased with the water injection scheme.
The recovery efficiency increased astronomically from 30%, as obtained with
natural depletion to 52%. The maximum oil production of 7200m3/day could be
sustained for four years and the production constraint of a keeping the plateau
for a 60% of the Estimated Ultimate Recovery could be met.
Also, the total oil production rose steadily and finally peaked at 18MMm3 in 14
years.
NWOSU, DIXON 61 IJEH, ISIJOKELU
Fig 3.13: Water Injection: FPR, FWCT and FWIR as a function of time
Since the oil production was done at a pressure above oil bubble point pressure,
the FGOR remained constant at a value of 0.2m3/m3. Reservoir pressure dropped
steadily from initial reservoir pressure to 296 bars and started rising at the start
of water injection. Field pressure rose very slowly from 296 bars to a final value
of 312 bars in 14 years.
The water injection wells were opened in the 16th month after the start of oil
production. Water injection was done mostly in the Tarbert region. For this 7-
well case, the water injection rate increased rapidly at the time of injection in
order to compensate for voidage already created before injection. Injection rate
then dropped gradually as the plateau rate (oil production) dropped too. The
average reservoir pressure was maintained above 300 bars as it gently rose. The
water cut also increased as the plateau rate was dropping which indicated that
the injected water has broken through and then being produced.
NWOSU, DIXON 62 IJEH, ISIJOKELU
3.3 Case 3: Gas Injection Preceded by Natural Depletion
This was simulated by re-defining the water injection wells as gas injection wells.
Gas was then injected into the reservoir when the reservoir pressure had
dropped to 290bars because the injected gas is most soluble in the oil at that
pressure.
Fig 3.14: Gas Injection: FOPR, FOE and FOPT as a function of time
The FOPR plateau at 7200m3 could only be sustained for 4 years and total oil
recovery was 15 million cubic metres of oil. FOE dropped to 42% as against 52%
that was obtained with water injection
NWOSU, DIXON 63 IJEH, ISIJOKELU
Fig 3.15: Water Injection: FPR, FWCT and FWIR as a function of time
From the production profile of the four wells case, proposed pressure
maintenance at 340 bars wasnt as successful as desired. But however, the rate of
pressure decline around 340 bars reduced for a while, it then reduced gradually
from 340 bars at 300 days to 290 bars at 4 years where it was then maintained
continuously.
Since the field oil recovery dropped by using gas injection, there are still
bypassed oil that were not recovered. This makes only the gas injection not very
suitable on an absolute scale, hence the need for combination with water.
3.4 Case 4: Water- Alternating Gas Injection
In this secondary recovery scheme, the reservoir was allowed to deplete to a
predetermined pressure after which water and gas were alternately injected.
Water-alternating gas schemes have proven very effective for secondary recovery
as gas injection schemes result in viscous fingering and reduced sweep
NWOSU, DIXON 64 IJEH, ISIJOKELU
efficiency. In WAG schemes, the injected water displaces the oil in the high
permeability layers while the gas displaces the oil in the low permeability zones.
Water is injected into the reservoir for a period of say two years with the same
conditions required for ordinary water injection. The water pumps are then shut
off and the gas compressors are started for injection of gas into the reservoir
through the same injection wells for a shorter duration. The duration of the
water and gas injections are continuously altered until favourable results are
obtained.
Four WAG cycles were considered:
Sub case 1: 2.5 years of water injection - 6 months of gas injection - 1.5
years of water injection - 6 months of gas injection-water injection.
Sub case 2: 32 months of water injection - 6 months of gas injection - 2
years of water injection - 6 months of gas injection - 18 months of water
injection-3 months of gas injection - 12 months of water injection - 3
months of gas injection - 12 months of water injection - 3 months of gas
injection - water injection
Sub case 3: 2.5 years of water injection - 6 months of gas injection - 2 years
of water injection - 6 months of gas injection - 2 years of water injection -
6 months of gas injection - 2 years of water injection - 6 months of gas
injection - 2 years of water injection - 6 months of gas injection -water
injection.
Sub case 4: 5 years of water injection-6 months of gas injection-2 years of
water injection-6 months of gas injection-2 years of gas injection-6 months
of gas injection-2 years of water injection-6 months of gas injection-water
injection.
The results are presented below:
NWOSU, DIXON 65 IJEH, ISIJOKELU
Fig 3.16: Sub-case 1: FOPT, FOE, FOPR, FWIR and FOPR as a function of time
Fig 3.17: Sub case 2: FOPR, FOPT, FOE, FWIR and FPR as a function of time.
NWOSU, DIXON 66 IJEH, ISIJOKELU
Fig 3.18: Sub case 3: FOPR, FOPT, FOE, FWIR and FPR as a function of time
Fig 3.19: Sub case 4: FOPR, FOPT, FOE, FWIR and FPR as a function of time
NWOSU, DIXON 67 IJEH, ISIJOKELU
Sub-case 3 was the most effective as it had the highest field oil recovery of 55%.
Sub-cases 1, 2 and 4 had field oil recoveries of 54%, 54.5% and 52 % respectively.
The pressure maintenance was effective around 350 bars and the decline in
plateau rate was gradual over time. The field gas oil ration rose gently over the
production period while the water cut rose steeply during the plateau
production and then unnoticeable slowly during the decline period.
There was fluctuation in the producing gas-oil ratio during the life of the
reservoir due to the alternating injection of water and gas with FGOR highest
during years of gas injection.
In conclusion, compared to the water injection case, WAG showed an overall
increase in FOE, FOPR, reduction in FWCT and better pressure maintenance.
Table 3.1: Comparison of WI and WAG
CASE
FOE (%)
FOPT (MM
Sm3)
FWCT (%) PLATEAU
(Years)
FPR
(Bar)
WI 50 18.30 85 3.8 310
WAG 55 18.75 80 4.2 350
WAG has a higher total oil production with reduced water production and
better pressure maintenance than the water injection scheme. This is due to the
fact that injecting gas; reduces the viscosity of oil which improves the sweep,
reduces the amount of injected water/water cut. WI exhibited a longer plateau
NWOSU, DIXON 68 IJEH, ISIJOKELU
CHAPTER FOUR
ECONOMIC ANALYSIS
The oil and gas business aims to maximize profitability of any prospect while
minimizing expenditures and associated uncertainties/risks, within a shorter
time frame. Hence, a key parameter for the justification of any petroleum
business is its economic viability.
The goal of this reservoir simulation project is to propose a development plan
for the Brent East reservoir that maximizes hydrocarbon production and
minimizes the development cost in $/bbl. In the previous chapter, the optimized
development cases for the different development scenarios were determined
after rigorous numerical simulations. This chapter will therefore, deal with the
economic evaluation of those optimal development options for the ALWYN
field.
The capital costs, operating costs, gross revenues, pay-back time and other
profitability indices will be determined for each of the development strategies
that were optimised in the previous chapter. The final project decision will then
be based on the economic evaluation results.
The following assumptions were made in the evaluation:
Oil price is pegged at $110/bbl.
OPEX is limited to the lifting, transportation and distribution costs only.
Other components of the operating expenditure that are based on
specific activities anticipated in the lifetime of the field were not
considered.
The already existing wells come at zero cost. They will be neglected in
the computation of the CAPEX
The cost of water and gas volumes used for the injection cases, as well as
their supportive surface handling equipment, was ignored.
Taxation costs is 40% of gross revenue
Maintenance costs, replacement costs, manpower costs,
decommissioning and well work over expenditures were not considered
NWOSU, DIXON 69 IJEH, ISIJOKELU
On-stream time was 7884 hours per year
The economic analysis will be based on the field development capital
and operating costs that were given in the November 2011 edition of the
Journal of Petroleum Technology
CAPEX
Treatment and Production Facilities Platform 700MM$
Drilling and Accommodation Platform 250MM$
Secondary Platform 250MM$
Drilling Cost per well for deviated wells from a platform 12MM$
Gas compressors 44.2MM$
OPEX
Lifting, Production and Transportation costs 6.5$/bbl
The following computed parameters were used to evaluate the profitability of
the different scenarios:
Revenue = Selling Price of oil x Volume of Produced Oil
Total CAPEX = Cost of drilling and accommodation facilities + Cost of
Production facilities
Total OPEX= Lifting costs x Volume of Produced oil
Depreciation = CAPEX/ Project life
Taxable Income= Gross Revenue Depreciation - Operating Expenses
Project tax bill = Taxation Rate x Taxable Income
Cash Flow = Revenue Investment - OPEX- Tax bill Discounted Factor = (1 + i) n
Discounted Cash Flow = Discount Factor x Cash Flow
Net Present Value = Cumulative NPV each year.
Gross Profit Margin = Gross Revenue Total Investment Costs
GPM per barrel = GPM/ Total Production
Profitability Index = Final CNPV/Total Investment
Pay Back Period = Time at CNPV is 0
NWOSU, DIXON 70 IJEH, ISIJOKELU
Internal Rate of Return, IRR = D.F at CNPV is 0
4.1 Economic Evaluation of Natural Depletion at Economic Limit
The natural depletion case represents the simplest and cheapest production
strategy. Production commences as soon as the production and treatment
facilities have been set up and no extra wells have to be drilled. Oil production
from the four available injection wells totalled 67.33 million barrels with a
recovery efficiency of 30%.
Table 4.1 Revenues and Expenditures for Natural Depletion
CAPITAL EXPENDITURE
Units/Cost
per barrel
Unit
Cost
in
MM$
Total Cost in
MM$
Treatment and Production
Facilities 1 700 700
Drilling and Accomm0dation
Platform with 40 Platform slots 1 250 250
Drilling Cost for Horizontal Wells 0 16 0
Drilling cost for Deviated/Vertical
Wells 2 12 24
Horizontal Subsea Well and Piping 0 40 0
Vertical Subsea well and Piping 0 36 0
Gas Injection Compressors 0 44.2 0
Total Capital Investment 974 974
OPERATING EXPENDITURE
Production and Transportation
Costs 67.33 6.5 437.6
TOTAL EXPENDITURE 1411.6 1411.6
Total Expenditure per barrel 20.96539433
PROFIT
Profit per barrel 89.03460567
Gross Profit Margin in MM$ 5994.7 5994.7
NWOSU, DIXON 71 IJEH, ISIJOKELU
Table 4.2 Economic Evaluation Indices for Natural Depletion
NATURAL DEPLETION
Total Oil Production in MMbbls 67.33
Total Investment in MM$ 724
Gross Revenue in MM$ 7406.3
Gross Profit Margin in MM$ 5994.7
Gross Profit Margin per barrel in MM$ 92.75
Profitability Factor 1.975138122
Cummulative Net Present value in MM$ 1430
Internal rate of Return in % 40%
Pay back Period 2.8 years
Project's Economic Life 9 years
With a gross profit of $5.99 billion dollars, over a fifteen year period, from a total
expenditure of 974 million dollars, this seems to be a very sound investment
strategy. For every barrel of oil produced, a gross profit of $89 is to be made.
Investors should also drool at the fact that the initial capital investments would
be recovered after only 2.7 years. Cumulative Net Present value stands at a
staggering 1.43 billion dollars and the profitability factor is 1.97.
The financial soundness of this production strategy is also backed by other
profitability indices. The internal rate of return is 42% which is far greater than
the projects rate of return.
NWOSU, DIXON 72 IJEH, ISIJOKELU
Fig4.1 Cash flow curve for Natural Depletion Scheme
However, the short economic life of the project might want to deter investors
from backing this option. The project is only economic for 9 years out of the 15
years that it is expected to run. The cash flow is fairly constant at 500 million
dollars for the first six years and peaks at 580 million dollars in the seventh year.
Economic decline sets in after the seventh year as cash flow is at the end of the
8th and 9th is 419 MM$ and 41 MM$ respectively. The project is no longer
economically viable after the 9th year.
At face value, this is profitable for any investor but the short economic life
represents a drawback.
Other development strategies will have to be evaluated to determine the most
profitable development option based on basic assumptions, available constraints
and data.
4.2 Economic Evaluation of Gas Injection Scheme at Economic Limit
The gas injection scheme consists of seven producers (four new wells) and five
injectors (four new wells) as well as the associated treatment and production
systems. A very expensive gas compressor is also installed on-site to facilitate the
injection of the gas at the required pressure. The gas injection strategy led to the
-1200
-1000
-800
-600
-400
-200
0
200
400
600
800
0 2 4 6 8 10
Cash flow in MM$
Time in years
Cash Flow for Natural Depletion
Cash Flow
NWOSU, DIXON 73 IJEH, ISIJOKELU
production of 92.25 million barrels with a recover