INSTITUTE OF PETROLEUM STUDIES
Dynamic Reservoir Simulation of the Alwyn TM Field using ECLIPSE
NWOSU UGONNA DIXON IJEH GIFT ISIJOKELU
IPS/MSC/PPD/201 4/240 IPS/MSC/PPD/2014/240 IPS/MSC/PPD/2014/235 IPS/MSC /PPD/2014/235
June 2015
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 7200m 3 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 term termss of prof profita itabil bility ity,, intern internal al rate rate of of return 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
1
IJEH, ISIJOKELU
ACKNOWLEDGEMENT ACKNOWLEDGEME NT 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
2
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
3
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
4
IJEH, ISIJOKELU
i. Tarbert Region ........................................................................................................ 44 Evaluation of E A : ......................... ...................................... .......................... .......................... .......................... .......................... .......................... ............. 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 Depletion with the Available Four Four Exploratory Wells Wells ..................... ........... .......... 49 3.1.2 Effect of Critical Gas Saturation ....................................................................... 52 3.1.3 Natural Depletion Depletion with 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 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 Ev aluation 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
5
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% 1 0% As The Discount Factor ................. ....... .......... 93 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
6
IJEH, ISIJOKELU
B2 Water Injection: Evaluation Of Npv Npv Using 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
7
IJEH, ISIJOKELU
LIST OF TABLESTable 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............... Drive......... ...... 34 Table 2.3: Reciprocal R eciprocal 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 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 ...................................................................67 Table 4.1 Revenues and Expenditures for Natural Depletion ....................... ........... .................... ........ 70 Table 4.2 Economic Evaluation Indices for Natural Natural Depletion...................... .......... ................... ....... 71 Table 4.3 Revenues and Expenditures for Gas Injection 73 Table 4.4 Economic Evaluation 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 Expenditures for WAG WAG Injection Injection ....................... ............ ...................... ............. 79 Table 4.8 Summary of of Economic Evaluation Parameters for WAG Injection .... 80 Table 4.9: Economic Evaluation for the various development schemes 87 NWOSU, DIXON
8
IJEH, ISIJOKELU
LIST OF FIGURES Figure1.1 Figure1.1:: Alwyn Alwyn North Field Localization Localization Map Map
7
Figure 1.2: Alwyn Area Area Location Map
8
Figure1.3: Figure1.3: Stratigraphy Stratigraphy of the Alwyn Alwyn North Field
9
Figure 1.6: Cross Sectio Section n Through Through Alywn Showing Showing The Faults
11
Figure 1.7: Depositional Setting of the Brent Group Figur Fig uree 1.8: 1. 8: Showin Showing g Log Correlations Correlatio ns
13
Figure 1.8: Rese Reservoir rvoir Model Model Showi ng the Grids
17
Figure 1.9: Data File Initiali zed to Obtain Volumes Volumes In-Place In-Place
19
Fig2.1: Reciprocal Mobility Ratio Chart
29
Fig2.2: Fractional Flow curve for the Tarbert Region Fig2.3: 32
Fractional
Flow
curve
for
31
the
Ness
Region
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 P N1
44
Fig 3.4: Field Recovery Efficiency and Field Plateau Rate for both cases 4 6 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 Fig 3.10:
49
Well by Well Analysis
50
Fig 3.11: Well Architecture: 7 producers and 5 injectors NWOSU, DIXON
9
52 IJEH, ISIJOKELU
Fig 3.12: Water Injection: FOPR, FOE and FOPT
53
Fig 3.13: Water Injection: FPR, FWCT and FWIR Fig 3.14: Gas Injection: FOPR, FOE and FOPT Fig 3.15: Water Injection: FPR, FWCT and FWIR
54 55 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
Fi g 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
10
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 pressure limit of 100bars 2. Natural depletion up to to a reservoir pressure 290bars then introduction introduction of Water injection as secondary recovery recovery process 3. Natural depletion to a reservoir pressure 350bars then introduction of Gas injection as secondary recovery process 4. Natural depletion depletion to a reservoir reservoir pressure pressure 350bars then introduction of Water injection as secondary recovery process for 4years 4 years 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
11
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
12
IJEH, ISIJOKELU
Figure Figure 1.2: Alwyn Area 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 NorthSouth direction, on the other hand by a major unconformity at the base of Cretaceous. This unconformity is related to erosion of the Brent B rent 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 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
13
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 deposited after after the tectonic activity. activity. Kimmeridge clay thick in the West, thin in the East, which is the main hydrocarbon source rock. Thick cretaceous sequence.
Figure1.3: Figure1.3: Stratigraphy Stratigraphy of the Alwyn Alwyn North Fiel d
ALWYN North reservoirs were relatively unaffected by diagenesis due probably to an early hydrocarbon 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
14
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 north –south 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 Figure 1.4: Brent Brent Geological Cross se ction
The Brent geological well section is shown in Fig. 1.5.
NWOSU, DIXON
15
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 NorthSouth direction, on the other hand by a major unconformity at the base of Cretaceous. This unconformity is related to erosion of the Brent B rent 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
16
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 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
17
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 shoreface environment. Three different 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
18
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 (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
19
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 P sat). In order to calculate the Material Balance, use average values of S wi 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 all relevant information, assumptions and selected NWOSU, DIXON
20
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 (S gc). 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: 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
21
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 represe representing nting the Tarbert and Ness
Rock Type
Type 1 Type 2
Formation
Layer Tags
Impermeable zone
1
Tarbert 3
2,3,4
Tarbert 2
5,6
Tarbert 1
7,8,9
Ness 2
10,11,12,13,14 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
22
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 co ntact (WOC) and pressure regime.
Figure 1.8: Rese Reservoir rvoir Model Model Showing the Gr ids
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
23
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
Properties Value Initial Reservoir Pressure (Pi) Temperature (T) 110 oC Saturation Pressure (Psat) GOR 206.8974 v/v Formation factor, Bo@ Pi OOIIP
446 Bar 258 Bar 1.6038 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
24
IJEH, ISIJOKELU
Table 1.3: Table Showing the Fluids in Place Volume
Currently in place Tarbert Ness Entire Field 31,104,045 4,577,946 35,681,991 Oil (sm3) 125,222,389 188,540,747 313,763,137 Water (sm3) Dissolved Gas 6,426,769,976 945,920,886 7,372,672,862
Figure Figure 1.9: Data File File Initialized to Obtai n Volumes Volumes I n-Place n-Place
NWOSU, DIXON
25
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 Sm 3,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 focused mainly on the Tarbert rock.
NWOSU, DIXON
26
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 investigated (material balance 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
27
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 2½ 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
28
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: 8°C). 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. in jected. 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-à- 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 Alwyn’s Tarbert and Ness formations. The following screenshot captures this information and other important data. NWOSU, DIXON
29
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
30
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 support or water water influx into the the reservoir 2. Recovery is by rock and and liquid expansion 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, pressure, 446bars
NWOSU, DIXON
31
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 C w = Compressibility of Water NWOSU, DIXON
32
IJEH, ISIJOKELU
So = Oil Saturation S wc = 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
33
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
34
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, µo & µw) Ea = f(mobility ratio, pattern, directional permeability, pressure distribution, cumulative injection & operations) Ev = f(rock f(rock property variation between 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
35
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
36
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
37
IJEH, ISIJOKELU
Tarbert 1.1 1 0.9 0.8 0.7 0.6
w f
Tarbert
0.5 0.4 0.3 0.2 0.1 0 0
0.2
0.4
0.6
Swm 0.8
1
1.2
Sw
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
NWOSU, DIXON
38
IJEH, ISIJOKELU
Table 2.5: Relative Permeability (Imbibition) data table
Swm
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% NWOSU, DIXON
39
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
40
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 μo = viscosity of oil NWOSU, DIXON
41
IJEH, ISIJOKELU
C =conversion factor K = permeability H = net pay thickness ΔP = pressure drawdown Rd = reservoir drainage radius Rw = well radius S = skin Assumptions for Calculation: Wells drilled and completed completed in the TARBERT Region Region Reservoir producing at Pseudo-steady state Oil flowing at connate water saturation saturation Reservoir drainage radius equals 400m
Values of average permeability, 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 µ o = 0.3916 Kro = 0.8 ΔZ = 8.0907 per layer* 8 layers *NTG = 64.7256 * 0.96883 = 62.7081m ™
Qo @ 280bars Bo = 1.6737 µ o = 0.2829 Kro = 0.8 NWOSU, DIXON
42
IJEH, ISIJOKELU
ΔZ = 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. zero-net-voidage. Subsequently, we determine the surface equivalent of this reservoir water which is calculated as:
NWOSU, DIXON
43
IJEH, ISIJOKELU
Implication: We need to drill at least 4 injection wells for optimal reservoir exploitation by voidage replacement. 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 inj ection 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 E A : The Mobility Ratio is first obtained, Reciprocal Mobility ratio estimated, and traced up to the corresponding gas cut curve to read off E A =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
44
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
45
IJEH, ISIJOKELU
Figure 2.4: Relative permeability versus gas saturation curves
NWOSU, DIXON
46
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
47
IJEH, ISIJOKELU
Table 2.7: Recoveries from combined Natural Depletion and Gas Injection
As shown in the table above, total total oil produced from Tarbert 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 1 9 %.
NWOSU, DIXON
48
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 Natura l 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 reservoir’s energy. This energy might b e due to a solution gas drive, aquifer and rock expansion, gravity drainage or water drive.
3.1.1 Natural Depletion Deplet ion with the Available Availab le Four Exploratory Expl oratory 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
49
IJEH, ISIJOKELU
Fig 3.1: Well Architecture: Natural Depletion from Wells PA2, PN2, PA1 and and PN1
Fig 3.2: FOPR, FOPT and FOE as a function of time for the 4-well Natural Depletion case
NWOSU, DIXON
50
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
51
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. stream.
3.1.2 Effect of Critical Cr itical Gas Saturation Satura tion 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 Field Plateau Production Rate for both cases
NWOSU, DIXON
52
IJEH, ISIJOKELU
Higher recoveries and longer plateaus were recorded for the simulation case with a critical gas saturation saturation of 10%. There was an increase in total 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 8MMm 3 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
53
IJEH, ISIJOKELU
Fig 3.6:
Comparing the Field Water Cut and Field Gas-Oil Ratio for both cases
3.1.3 Natural Depletion Deplet ion with Increased Development Deve lopment 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 Deplet ion with Five Producer Produc er 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
54
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 fu nc ti on of ti me
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
55
IJEH, ISIJOKELU
Fig 3.9: Natural Depletion with 5 Producers: FPR, FOE, FWCT, FGOR as a fu nc ti on of ti me
Fig 3.10:
Well by Well Well Analysis: Analysis: Individual Oil Well Production Rate as a fu nc ti on of ti me
NWOSU, DIXON
56
IJEH, ISIJOKELU
3.1.4 Inferences: Natural Nat ural 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 displayed above. above. EUR from the natural depletion depletion varied from 20% 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 replacement of the gas gas and oil withdrawals. 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
57
IJEH, ISIJOKELU
3.2: Case 2: Water Injection Preceded by Natural N atural Depletion Deple tion 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
58
IJEH, ISIJOKELU
Fig 3.11: Well Architecture: 7 producers and 5 injectors. Wel l PA2 is an injection well
NWOSU, DIXON
59
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 18MMm 3 in 14 years.
NWOSU, DIXON
60
IJEH, ISIJOKELU
Fig 3.13: Water Injection: FPR, FWCT and FWIR 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 0.2m 3/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 16 th month after the start of oil production. Water injection was was done mostly in the Tarbert 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
61
IJEH, ISIJOKELU
3.3 Case 3: Gas Injection Injecti on Preceded by b y Natural Depletion Depl etion 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 7200m 3 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
62
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 wasn’t 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: WaterWater - 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 gas schemes have proven very very effective for secondary secondary recovery as gas injection schemes result in viscous fingering and reduced sweep NWOSU, DIXON
63
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 i s 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 injection - 6 months of gas injection-water 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 gas injection-2 years of gas injection-6 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
64
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 and FPR as a function of time.
NWOSU, DIXON
65
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
66
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 FOPT (MMFWCT (%) Sm3)
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
67
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 $110/bbl. OPEX is limited to the lifting, transportation and distribution costs only. Other components of the operating expenditure that are based on specific activities anticipated in the lifetime of the field were not considered. The already existing wells come at zero cost. They will be neglected in the computation of the CAPEX The cost of water and gas volumes used for the injection cases, as well as their supportive surface handling equipment, was ignored. Taxation costs is 40% of gross revenue Maintenance costs, replacement costs, manpower costs, decommissioning and well work over expenditures were not considered
NWOSU, DIXON
68
IJEH, ISIJOKELU
On-stream time was 7884 hours per year The economic analysis will be based on the the field development capital and operating costs that were given in the November 2011 edition of the Journal of Petroleum Technology
CAPEX Treatment and Production Facilities Platform Drilling and Accommodation Accommodation Platform Secondary Platform Drilling Cost per well for deviated wells from a platform Gas compressors OPEX Lifting, Production and Transportation costs
700MM$ 250MM$ 250MM$ 12MM$ 44.2MM$
6.5$/bbl
The following computed parameters were used to evaluate the profitability of the different scenarios: Revenue = Selling Price of oil x Volume of Produced Oil Total CAPEX = Cost of drilling and accommodation facilities + Cost of Production facilities Total OPEX= Lifting costs x Volume of Produced Produced oil Depreciation = CAPEX/ Project life Taxable Income= Gross Revenue – Depreciation - Operating Expenses Project tax bill = Taxation Rate x Taxable Income Cash Flow = Revenue – Investment - OPEX- Tax bill Discounted Factor = (1 + i) –n Discounted Cash Flow = Discount Factor x Cash Flow Net Present Value = Cumulative NPV each year. Gross Profit Margin = Gross Revenue – Total Investment Costs GPM per barrel = GPM/ Total Production Profitability Index = Final CNPV/’Total Investment Pay Back Period = Time at CNPV is 0
NWOSU, DIXON
69
IJEH, ISIJOKELU
Internal Rate of Return, IRR = D.F at CNPV is 0
4.1 Economic Evaluation of Natural Depletion at Economic Limit The natural depletion case represents the simplest and cheapest production strategy. Production commences as soon as the production and treatment facilities have been set up and no extra wells have to be drilled. Oil production from the four available injection wells totalled 67.33 million barrels with a recovery efficiency of 30%. Table 4.1 Revenues and Expenditures for Natural Depletion
C APITAL EXPENDITURE Treatment and Production Facilities Drilling and Accomm0dation Platform with 40 Platform slots Drilling Cost for Horizontal Wells Drilling cost for Deviated/Vertical Wells Horizontal Subsea Well and Piping Vertical Subsea well and Piping Piping Gas Injection Compressors Total Capital Investment Investment OPERATING EXPENDITURE Production and Transportation Costs TOTAL EXPENDITURE EXPENDITU RE Total Expenditure per barrel PROFIT Profit per barrel Gross Profit Margin in MM$
NWOSU, DIXON
Units/Cost per barrel
Unit Cost in MM$
Total Cost in MM$
1
700
700
1 0
250 16
250 0
2 0 0 0
12 40 36 44.2
24 0 0 0 974
67.33
6.5
974
437.6 1411.6 20.96539433 89.03460567 5994.7
70
1411.6
5994.7
IJEH, ISIJOKELU
Table 4.2 Economic Evaluation Indices for Natural Depletion NATURAL DEPLETION Total Oil Production in MMbbls Total Investment in MM$ Gross Revenue in MM$ Gross Profit Margin in MM$ Gross Profit Margin per barrel in MM$ Profitability Factor Cummulative Net Present value in MM$ Internal rate of Return in % Pay back Period Project's Economic Life
67.33 724 7406.3 5994.7 92.75 1.975138122 1430 40% 2.8 years 9 years
With a gross profit of $5.99 billion dollars, over a fifteen year 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 $89 is to be made. Investors should also drool at the fact that the initial capital investments would be recovered after only 2.7 years. Cumulative Net Present value stands at a staggering 1.43 billion dollars and the profitability factor is 1.97. The financial soundness of this production strategy is also backed by other profitability indices. The internal rate of return is 42% which is far greater than the project’s rate of return.
NWOSU, DIXON
71
IJEH, ISIJOKELU
Cash Flow for Natural Depletion 800 600
Cash flow in MM$
400 200 0 -200 0 -400
2
4
6
8
10 Cash Flow
Time in years
-600 -800 -1000 -1200
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
NWOSU, DIXON
72
IJEH, ISIJOKELU
production of 92.25 million barrels with a recovery efficiency of 42%. The production and investment data are given below: Table 4.3 Revenues and Expenditures for Gas Injection GAS INJECTION PRODUCTION DATA OOIP in MMSm3 Fractional Oil Recovery Unrecoverable Oil in MMSm 3 Produced Oil in MMSm3 Produced Oil in MMbbl REVENUE Selling Price per barrel in $
35.68 42 20.6944 14.9856 92.25
Gross Revenue in MM$
10147.5
C APITAL EXPENDITURE EXPENDITURE Treatment and Production Facilities Drilling and Accomodation Platform with 40 Platform slots Drilling Cost for Horizontal Wells Drilling cost for Deviated/Vertical Wells Horizontal Subsea Well and Piping Vertical Subsea well and Piping Piping Gas Injection Compressors Total Capital Investment Investment OPERATING EXPENDITURE Production and Transportation Costs TOTAL EXPENDITURE
NWOSU, DIXON
110
Units/Cost per barrel
Total Unit Cost Cost in in MM$ MM$
1
700
700
1
250
250
0
16
0
8
12
96
0 0 1
40 36 44.2
0 0 44.2 1090.2
1090.2
599.625 1689.825
1689.825
92.25
6.5
73
IJEH, ISIJOKELU
Total Expenditure per barrel PROFIT Profit per barrel Gross Profit Margin in MM$
18.317886 91.682114 8457.675 8457.675
Table 4.4 Economic Evaluation Indices for Gas Injection GAS INJECTION Total Oil Production in MMbbls Total Investment in MM$ Gross Revenue in MM$ Gross Profit Margin in MM$ Gross Profit Margin per barrel in MM$ Profitability Factor Cummulative Net Present value in MM$ Internal rate of Return in % Pay back Period Project's Economic Life
92.25 1090.2 1014.5 8457.675 91.68 2.494606494 2719.62 84.68 1.3 years 11 years
This field development scenario has all the trapping of an investor’s delight. 8.46 billion dollars to be made on an investment of 1.09 billion dollars is absolutely astonishing. 91.68 dollars of gross profit per barrel is to be made on a barrel cost of 18.32 18.32 dollars is completely unbelievable but the figures don’t lie. A project is usually considered profitable if its Internal Rate of Return (IRR) exceeds the project’s discount rate (DR). This is observed in this development option as the IRR of 84.68% is by far greater than its DR of 10%. A project with shorter payback period is usually preferred as investors are assured of timely break-even, and hence profit in a shorter time. As the Net Present Value (NPV) measures the present days’ worth of a project’ s future revenue or worth; a positive NPV indicates that the project of concern is profitable. The payback period of 1.3 years, for an economic project life of 11 years, and a high positive Net Present Value (NPV) of $2.719 billion, are NWOSU, DIXON
74
IJEH, ISIJOKELU
individually positive positive indicators of a project’s economic feasibility, among other profit indicators.
Cash Flow for Gas Injection
1500
Cash flow in MM$ 1000 500 0 0
2
4
6
8
10
Time in years
12
14
16
-500 -1000
-1500
Fig4.2
Cash flow for Gas Injection
However, just as in the previous case, the project isn’t economic throughout its whole life. It stops being economic in the 11 th year and losses of over 84 million dollar will be made in the 12 th year. After pay back in 1.3 years, investors begin to have positive cash flow which maintains a fairly constant plateau of one billion dollars for 2.7 years. Revenues begin to slump continuously as from the 4 th year until the 11 th year when losses begin to set in. The project stops being economic at this point as the field is no longer producing but production costs still have to be shouldered. The total losses to be taken for the last four years are projected at 84 million dollars. This picture won’t be very exciting to investors who are willing to stump 1.09 billion dollars in the high-risk oil and gas business. Depending on the business strategy of the investor, the gas injection scheme represents a profitable development option if the investors are willing to make profit in the first 10.7 years after pay-back years, take losses in the 12 th year and expect no revenue up till the 15 th year. NWOSU, DIXON
75
IJEH, ISIJOKELU
4.3 Economic Analysis of Water Injection Scenario A major assumption made in the economic analysis of this strategy is that the costs associated with injecting water into the wells are negligible. In this case, 52% oil recovery is obtained from producing oil using a scheme that comprises seven producers and five injectors. The total volume of oil produced was 116.23MM barrels Table 4.5 Revenues and Expenditures for Water Injection WATER INJECTION INJECTION PRODUCTION DATA OOIP in MMSm3 Fractional Oil Recovery Unrecoverable Oil in MMSm 3 Produced Oil in MMSm3 Produced Oil in MMbbl REVENUE Selling Price per barrel in $ Gross Revenue in MM$
C APITAL EXPENDITURE Treatment and Production Facilities Drilling and Accomodation Platform with 40 Platform slots Drilling Cost for Horizontal Wells Drilling cost for Deviated/Vertical Wells Horizontal Subsea Well and Piping Vertical Subsea well and Piping Piping Gas Injection Compressors Total Capital Investment Investment OPERATING EXPENDITURE Production and Transportation
NWOSU, DIXON
35.68 51.8 17.2 18.48 116.23 110 12785.3
Units/Cost per barrel
Unit Cost in MM$
Total Cost MM$
1
700
700
1 0
250 16
250 0
8 0 0 0
12 40 36 44.2
96 0 0 0 1046
116.23
76
6.5
in
1046
755.495
IJEH, ISIJOKELU
Costs TOTAL EXPENDITURE Total Expenditure per barrel PROFIT Profit per barrel Gross Profit Margin in MM$
1801.495 15.499398
1801.495
94.500602 10983.81 10983.805
Table 4.6 Summary of Economic Evaluation Parameters for Water Injection WATER INJECTION Total Oil Production in MMbbls Total Investment in MM$ Gross Revenue in MM$ Gross Profit Margin in MM$ Gross Profit Margin per barrel in MM$ Profitability Factor Cumulative Net Present value in MM$ Internal rate of Return in % Pay back Period Project's Economic Life
116.23 1046 12785.3 10983.81 94.5 3.256879541 3406.696 90.4 1.2 years `15 years
Via this scheme, 10.9 billion dollars is to be made from an initial capital investment of 1.05 billion dollars. A profit of 94.5 dollars is to be made for every barrel of oil produced which comes at a cost of 15.5 dollars. The Net Present Value is a staggering 3.19 billion dollars while investors are expected to recover their initial outlay of 1.05 billion dollars in 1.2 years. Profitability factor stands at an impressive 3.05 while internal rate of return is at an even more impressive 92% in contrast to the discount rate of 10%.
NWOSU, DIXON
77
IJEH, ISIJOKELU
1500
Cash Flow Curve for Water Water Injection Scheme Cashflow in MM$
1000
500
0 0
2
4
6
8
10
12
14
16
Time in years
-500
-1000
-1500
Fig4.3
Cash flow for Water Injection
After pay back in 1.2 years, investors begin to have positive cash flow which maintains a fairly constant plateau of one billion dollars for 2.7 years. Revenues begin to slump continuously as from the 4 th year to 500 million dollars in the 6 th year to about 81 million dollars in the 11 year. As from the 11 th year, huge cash flows are no longer guaranteed but there is cash flow all through the producing life of the field. The cash flow in the 12 th year is 36 million dollars and slumps even more to an all-time low of 24 million dollars at the end of the project’s pr oject’s life. With this scheme, investors are guaranteed profit throughout the producing life of the project as the project is economic all through. Clearly, this is a production scheme that investors should look into as all its economic indices are positively high. This scheme outperforms the gas injection and natural depletion production schemes in all aspects.
4.4 Economic Analysis of the Water-Alternating-Gas Scheme In this scheme, water and gas are alternately injected through five injection wells and produced through seven producers to give a field oil recovery of 55% and a total oil production of 123.42 12 3.42 million barrels.
NWOSU, DIXON
78
IJEH, ISIJOKELU
Table 4.7 Revenues and Expenditures for WAG Injection WATER ALTERNATING GAS INJECTION PRODUCTION DATA OOIP in MMSm3 35.68 Fractional Oil Recovery 55 3 Unrecoverable Oil in MMSm 16.056 Produced Oil in MMSm3 19.624 Produced Oil in MMbbl 123.42 REVENUE Selling Price per barrel in $ Gross Revenue in MM$
C APITAL EXPENDITURE Treatment and Production Facilities Drilling and Accomodation Platform with 40 Platform slots Drilling Cost for Horizontal Wells Drilling cost for Deviated/Vertical Wells Horizontal Subsea Well and Piping Vertical Subsea well and and Piping Gas Injection Compressors Total Capital Investment Investment OPERATING EXPENDITURE Lifting, Production and Transportation Costs TOTAL EXPENDITURE Total Expenditure per barrel PROFIT Profit per barrel Gross Profit Margin in MM$
NWOSU, DIXON
110 13576.2
Units/Cost per barrel
Unit Cost in MM$
Total Cost in MM$
1
700
700
1 0
250 16
250 0
8 0 0 1
12 40 36 44.2
96 0 0 44.2 1090.2
123.42
6.5
802.23 1892.43 15.333252
1090.2
1892.43
94.666748 11683.77 11683.77
79
IJEH, ISIJOKELU
Table 4.8 Summary of Economic Evaluation Parameters for for WAG WAG Injection WAG INJECTION Total Oil Production Total Investment Gross Revenue Gross Profit Margin Gross Profit Margin per barrel Profitability Factor Cumulative Net Present value Internal rate of Return Pay back Period Project's Economic Life
92.25 1090.2 13576.2 11683.77 94.66 3.2224211 3513.083483 85% 1.3 years 15 years
The gross revenues to be made from this scheme far outstrip whatever investment costs that might have been outlaid for the project. Investors are expected to bag over 11.68 billion dollars from an initial investment i nvestment of 1.09 billion dollars that would be recouped in 1.3 years. 94 .66 dollars of oil is expected to be made for every barrel of oil that costs 15.33 dollars. The Net Present Value is a monstrous 3.513billion dollar, profitability factor is 3.22 and the internal rate of return is highly impressive at 85%.
NWOSU, DIXON
80
IJEH, ISIJOKELU
1500
Cash Flow for WAG Injection CashFlow in MM$ 1000
500
0 0
2
4
6
8
10
12
Time in Years
14
16 Cash Flow
-500
-1000
-1500
Fig 4.4: Cash flow for WAG Injection
After pay back in 1.3 years, investors begin to have positive cash flow which maintains a fairly constant plateau of one billion dollars for 2.7 years. Revenues begin to slump continuously as from the 4 th year to 632 million dollars in the 6 th year to about 115 million dollars in the 11 year. As from the 11 th year, huge cash flows are no longer guaranteed but there is cash flow all through the producing life of the field. The cash flow is constant for the next two years at 95 million dollars, reduces to 74 million dollars in the 14 th year and slumps to a final value of 65 million dollars in the 15th year. `
4.5 Investment Decision The four schemes are very profitable and will guarantee high returns for any willing investor. However, the investor would like to maximize returns on committing huge funds into the high-risk oil and gas business. Hence, there is a need to juxtapose the economic evaluations of the described cases to ascertain the scheme that will yield optimum returns on investment. In making the final investment decision, the following questions have to be answered by the investor What scheme has the lowest risk or has the lowest capital capital investments?
NWOSU, DIXON
81
IJEH, ISIJOKELU
How fast can I get my initial outlay back? What scheme yields yields maximum profits? profits? What scheme yields yields maximum profits relative to the amount amount invested? What scheme satisfies satisfies a short-term investment investment strategy? strategy? What scheme satisfies satisfies a long-term investment investment strategy? strategy? What scheme yields yields the highest Net Present value on investments? investments?
4.5.1 Lowest Capital Investment The huge volume of the funds required for the field development necessitates the minimisation of investment costs. For the four schemes, investment costs range from 774 million dollars to 1090 million dollars. Sourcing funds of this volume would not be an easy task at all as it might require a consortium of banks to provide the necessary loan facility. 16 14 $12 M M 10 n i s t s 8 o C t n 6 e m t s 4 e v n I
2 0
Natural Depletion
Water Injection
Gas Injection
WAG Injection
Fig 4.5: Investment Costs for the various development schemes
An investor, with limited borrowing power and weak financial muscle, should simply settle for the natural depletion strategy as it limits his financial exposure. He is more willing to settle for the cheapest project as the profitability of all the schemes has been certified.
NWOSU, DIXON
82
IJEH, ISIJOKELU
4.5.2 Pay-back time The pay-back time is a measure of the time required to recoup the initial outlay that was invested into a project. This is the length of time required to recover the cost of a project. The payback period of a given project is an important determinant of whether to undertake the position or project, as longer payback periods are typically not desirable for investment positions (Investopedia, 2014). The water injection scheme has the lowest pay-back time of 1.2 years while natural depletion has the highest pay-back time of 2.8 years. Even though natural depletion has the pay-back time of 2.7 years, it should not be discounted for this reason as the pay-back time is favourable. f avourable. Water Injection, gas Injection and WAG injections are the top performers performers in this regard. 16 14 12 e m i 10 t k c a b -8 y a P
6 4 2 0 Natural Depletion
Water Injection
Gas Injection
WAG Injection
Fig 4.6 4.6 : Pay-back time for the various development development schemes
NWOSU, DIXON
83
IJEH, ISIJOKELU
4.5.3 Profitability Index and Economic Life 16
14
12
10
Economic Life
8
Profitability Index 6
4
2
0 Natural Depletion
Water Injection
Gas Injection
WAG Injection
Fig 4.7: 4.7: Economic Life and PI for the various development schemes schemes
The profitability index is an evaluation that attempts to identify the relationship between the costs and benefits of a proposed project through the use of a ratio of the Present Value of Future Cash Flows to the Initial Investment of the project. The attractiveness of a proposed project increases directly with the PI. Based on this, water injection appears to be most profitable. WAG injection follows closely while gas injection and natural depletion are third and fourth respectively. The water injection schemes and WAG injection schemes could see out the proposed project life of 15 years at economic conditions. However, the gas injection scheme and natural depletion scheme had an economic life of 11 years and 9 years respectively.
NWOSU, DIXON
84
IJEH, ISIJOKELU
4.5.4 Gross Profit Margin per barrel
GPM per barrel 96 95 94 93 92 91
GPM per barrel
90 89 88 87 86 Natural Depletion Water Injection
Gas Injection
WAG Injection
Fig 4.8 GPM per barrel barrel for the various various development development schemes schemes
This is a financial metric used to assess a project’s profitability by revealing the proportion of profit realisable per unit of production. For comparative purpose, a project with the highest GPM is usually favoured over the others. In view of this, water injection had the highest gross profit per barrel while WAG injection follows closely again.
NWOSU, DIXON
85
IJEH, ISIJOKELU
4.5.5 Cumulative Net Present Value (CNPV):
NPV 4000 3500 3000 2500 2000
NPV
1500 1000 500 0 Natural Depletion
Water Injection
Gas Injection
WAG Injection
Fig 4.9 NPV for the various development schemes
Due of the time value of money, a dollar earned in the future won’t be worth as much as one earned today. This is accounted for by the discount rate in the NPV formula. The NPV therefore calculates the present worth of future cash flows of a project, to determine determine its profitability. profitability. The higher it is, the the better the project’s project’s profitability. In view of this, WAG shows the highest potential.
4.5.6 Internal Rate of Return (IRR): This is the discount rate often used in capital budgeting that makes the net present value of all cash flows from a particular project equal to zero. Generally speaking, the higher a project’s internal rate of return, the more desirable it is to undertake the project. As such, IRR can be used to rank several prospective projects a firm is considering. Assuming all other factors are equal among the various projects, the project with the highest IRR would probably be considered the best. Water Injection therefore appears to be the most economically profitable.
NWOSU, DIXON
86
IJEH, ISIJOKELU
IRR 100 90 80 70 60 50
IRR
40 30 20 10 0 Natural Depletion
Water Injection
Gas Injection
WAG Injection
Fig 4.10 IRR for the various development schemes
Table 4.9: Summary of Economic Evaluation Parameters for the various development schemes
IRR
GPM
PI
Natural Depletion
40
89
1.975
Water Injection
90.4 94.5
3.257
Gas Injection
84
91.68
2.436
WAG Injection
85
94.66 3.222
NWOSU, DIXON
Pay back Time 2.8 years 1.2 years 1.3 years 1.3 years
87
Economic Life NPV
Oil CAPEX Production
9 years
1430
724
`15 years
3406.696 1046
116.23
11 years
2656
1090.2
92.25
15 years
3513.083
1090.2
123.42
67.33
IJEH, ISIJOKELU
CHAPTER FIVE CONCLUSION AND RECOMMENDATIONS 5.1
Conclusion
From the performances of the individual development options against the economic indicators as detailed in the previous chapter, the following were determined: 1. All the development options are economically feasible, with Natural Depletion option as the least performer. 2. The WAG scheme has the highest Net Present Present Value (NPV). 3. The WI scheme has the highest Gross Profit Margin Margin (GPM) per barrel, highest Productivity Index (PI), highest Internal Rate of Return (IRR), and the shortest Pay-Back Period. Proper judgement of the economic profitability of a project requires making decisions based on the performances of candidate options against more than one economic indicator. In view of this, the WI option is therefore favoured over the WAG option. This is further consolidated by the fact that the additional cost of supportive facilities for gas injection were not accounted for in this study, which might offset the NPV margin margin of WAG over WI. It is also usually preferable preferable (were possible) to maintain single phase flow for ease of reservoir surveillance and management, as well as management of surface facilities. It is important to note that these results will change with alterations in operating cost, crude oil prices, logistics, regulations, host government policy, and petroleum fiscal systems among other factors. The Water injection scheme showed a higher profit, lower capital investment, a longer production plateau and a better recovery. It is clearly the most profitable scheme and is recommended because well effluent will always be single phased and surface facilities will not have to encounter a lot of gas. NWOSU, DIXON
88
IJEH, ISIJOKELU
5.2
Recommendations
The WI field development strategy is recommended for the ALWYN field. The following studies and approaches are highly recommended: 1. Further studies to determine the optimal optimal wells placement placement for the the field, field, as such will add to recovery. 2. Compatibility test test on the water to be used for the injection programme. 3. Strategic production approach to avoid early water water coning problems. This This includes monitoring of the WOC at the vicinity of the wells. 4. Continual improvement of the model as the field field is brought upstream. upstream. 5. EOR method after 14 years to sweep sweep the remaining oil in place. 6. The economic analysis is highly simplistic and more factors factors should have to be taken into account to give a true picture of the economics the various development schemes. 7. A compositional model model (employing ECLIPSE 300) that captures captures the effects of gas solubility on production enhancement should be used for the simulation. A compositional model captures the dynamism of PVT properties of the fluid and mimic thermodynamic processes processes such as gas miscibility with oil which is responsible for recovery efficiency. The black oil model (ECLIPSE 100) is i s limited as regards the aforementioned
NWOSU, DIXON
89
IJEH, ISIJOKELU
REFERENCES 1. Sakthikumar, S., (2010) Lecture Notes on Reservoir Simulation, Institute of Petroleum Studies, University of Port-Harcourt/IFP Training, France, Unpublished. 2. Ahmed, T., (2010), Reservoir Engineering Handbook; Fourth edition. 3. Cosse, R., (1998) Basics of Reservoir Engineering, Editions Technip, Paris. 4. Ahmed, T., and McKinney, P.D., (2005) Advanced Reservoir Engineering, Elsevier, Oxford. 5. Eclipse® Reference manual
NWOSU, DIXON
90
IJEH, ISIJOKELU
NOMENCLATURE List of Abbreviations FGOR:
Field Gas-Oil Ratio FOE: Field Oil Recovery Factor (%)
FOIP:
Field Oil In Place
FORFE:
Field fraction total oil produced by expansion
FORFF:
Field fraction total oil produced by free gas influx
FORFG:
Field fraction total oil produced by gas influx
FORFR:
Field fraction total oil produced by rock expansion
FORFS:
Field fraction total oil produced by solution gas
FORFW:
Field fraction total oil produced by water influx
FOPT:
Cumulative Field Oil Production cumulative total
FOPR:
Field Oil Production
FPR:
Field Pressure
FWCT:
Field Water-Cut
FWPR:
Field Water production rate
FWPT:
Field Water Production cumulative total
ROIP:
Regional Oil in Place WBHP: Well
Bottom-Hole
Pressure
WGOR :
Well Gas-Oil Ratio
WOPR:
Well Oil Production Rate
WWCT:
Well Water-Cut Water-Cut
NWOSU, DIXON
91
IJEH, ISIJOKELU
APPENDICES A: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate Of Return , Pay-Back Time And Npv For The Various Development Schemes Using 10% As The Discount Factor
A1 Natural Natu ral Depletion: Deple tion: Evaluatio Eval uation n Of Revenue, Reven ue, Opex, Cash Flow, Internal Inter nal Rate Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor NATURAL DEPLETION Oil Price Price = $110/bbl $110/bbl Dis c. rate= rate= 10%
Prod. in
Prod. in Year Year Disc. F bbls 0
3
MMm
Tax Bill
CAPEX Revenue Depr OPEX Income
1
0
0
1 0. 0.909
8.427673
2 0.8 0.826
0
1.34
927.044 64. 64.93
54.78
807.3308 32 322.9 484.3985
440.3623 -64 -649.84
8.36 .3647799
1.33
920.126
64.93 54 54.371
800.8214 320 320.3 48 480.4928
397.10 .1015
-25 -252.74 .74
3 0.751
8.427673
1.34
927.044
64 64.93
54.78
807 807.3308 322.9 484.3985
36 363.9358
111.2
4 0. 0.683
8.427673
1.34
927.044 64. 64.93
54.78
807.3308 32 322.9 484.3985 330 330.8507
442.05
5 0.6 0.621
8.86 .8679245
1.41
975.472
64.93 57 57.642
852.8969 341 341.2 51 511.7381
317.74 .7491 75 759.79 .799
8.427673
1.34
927.044
64. 64.93
807.3308
273 273.43 .4303 1033.23
7 0.5 0.51 13 10. 10.377358
1.65
1141.51 64. 64.93 67.453
1009.12 .123 40 403.6
605.47 .474
310.70 .7039 1343.93
8 0.4 0.467
7.79 .7987421
1.24
857.862
64.93 50 50.692
742.2365 296 296.9 44 445.3419
207.75 .7553 15 1551.69
9 0.4 0.424
1.69 .6981132
0.27
186.792
64.93 11 11.038
110.8214 44. 44.33 66 66.49283
28.19 .19945 15 1579.89
10 0.386
0
0
0
64.93
0 -64.93333
- 26
- 38.96 - 15.02077 1564.87
11
0.35
0
0
0
64.93
0 -64.93333
- 26
- 38.96 - 13.65524 1551.21
12 0.319
0
0
0
64.93
0 -64.93333
- 26
- 38.96 - 12.41386
13
0.29
0
0
0
64.93
0 -64.93333
- 26
- 38.96 - 11.28532 1527.51
14 0.263
0
0
0
64.93
0 -64.93333
- 26
- 38.96 - 10.25939 1517.25
15 0.239
0
0
0
64.93
0 -64.93333
- 26
- 38.96 - 9.326714 1507.93
0.5 0.56 64
0
54.78
0
0
- 1090.2
NPV
32 322.9 484.3985
IR R
- 1090.2
Cum.NP V
0
6
974
Cash Fl ow
- 1090.2
1538.8
42% 42%
PAYBACK PERIOD 2.7 YEARS
NWOSU, DIXON
92
IJEH, ISIJOKELU
A2 Gas Inject I njection: ion: Evaluatio Eval uation n Of Revenue, Reve nue, Opex, Cash Flow, Flow , Internal Int ernal Rate Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor GAS INJECTION Oil Price Price = $110/bbl $110/bbl
Dis c. rate= rate= 10%
0
Depre ciatio CAPEX Revenue n OPEX
Prod. Prod. in
Prod. Prod. in Yea Disc. F bbls
3
MMm
1
0
0
1090
0
1 0.90 0.909 9
16.1 16.163 6352 522 2
2.5 2.57
1777 1777.9 .99 9
2 0.82 0.826 6
16.7 16.761 6100 006 6
2.66 .665
3 0.75 0.751 1
16.3 16.389 8993 937 7
4 0.68 0.683 3 5
0
Taxable Income 0
Tax Bill 0
Cash Fl ow 0
Cum. NPV
NPV
-1090.2
- 1090.2
- 1090.2
72.6 72.68 8 10 105.0 5.06
160 1600.2 0.245 64 640.1 0.1 96 960.1 0.1467 467
872.8 72.860 607 7
-21 -217.3 7.34
1843 1843.7 .71 1
72.6 72.68 8 10 108.9 8.95
166 1662.0 2.084 66 664.8 4.8 99 997.2 7.2505 505
824 824.17 .174 606 606.8 .83 35
2.60 .606
1802 1802.8 .89 9
72.6 72.68 8 106. 106.5 53
162 1623.6 3.678 649. 649.5 5 974. 974.2 2071 071
731.9 31.936 362 2 133 1338.7 8.77
16.5 16.566 6603 038 8
2.63 .634
1822 1822.2 .26 6
72.6 72.68 8 107. 107.6 68
164 1641.9 1.905 656. 656.8 8 985. 985.1 1429 429
672.8 72.865 659 9 201 2011.6 1.64
0.6 0.62 21
8.8 8.8679 679245 245
1.4 1.41
975. 975.4 472
72. 72.6 68 57.6 57.64 42
845 845.15 .1502 338. 338.1 1 507. 507.0 0901 901
314. 314.8 8631 631
6 0.56 0.564 4
6.6 6.6352 352201 201
1.05 .055
729. 729.8 874 72.6 72.68 43.1 43.12 29
614 614.06 .0653 245. 245.6 6 368. 368.4 4392 392
207.9 07.974 743 3 253 2534.4 4.47
7 0.51 0.513 3
4.2 4.2641 641509 509
0.67 .678
469. 469.0 057 72.6 72.68 27.7 27.71 17
368 368.65 .6596 147. 147.5 5 221. 221.1 1958 958
113.5 13.508 084 4 264 2647.9 7.98
8
0.4 0.46 67
2.7 2.7672 672956 956
0.4 0.44
304. 304.4 403
72. 72.6 68 17.9 17.98 87
213 213.73 .7351 85.4 85.49 9 128. 128.2 2411 411
59. 59.825 8254 270 2707.8 7.81
9 0.42 0.424 4
1.8 1.8113 113208 208
0.28 .288
199. 199.2 245 72.6 72.68 11.7 11.77 74
114 114.79 .7917 45.9 45.92 2 68.8 68.87 7502 502
29.2 9.2097 0973 273 2737.0 7.02
2326 2326.5 .5
10
0.38 .386
1.1 1.1509 509434 434
0.18 .183
126. 126.6 604 72.6 72.68 7.4 7.4811 811
46.4 46.442 4264 64 18.5 18.58 8 27.8 27.86 6558 558
10.7 0.7433 4339 274 2747.7 7.76
11
0.3 0.35
0.9 0.9874 874214 214
0.15 .157
108. 108.6 616 72.6 72.68 8 6.4 6.418 182 2
29.5 29.518 1811 11 11 11.81 .81 17 17.71 .71087 087
6.20 .20755 7551 275 2753. 3.9 97
12 0.31 0.319 9
0.0 0.0628 628931 931
0.0 0.01
6.9 6.91824 1824 72.6 72.68 8 0.4 0.408 088 8 -66 -66..170 17057
-26. -26.5 5
-39. -39.7 7023 023 -12. -12.6 6503 5039 274 2741. 1.3 32
13
0.29
0
0
0
72.68
0
-72.68
- 29.1
-43.608 - 12.63168 2728.69
14
0.263
0
0
0
72.68
0
-72.68
- 29.1
-43.608 - 11.48335
15
0.239
0
0
0
72.68
0
-72.68
- 29.1
-4 -43.608 - 10.43941 2706.76
I RR
2717.2
85%
PAYBACK PERIOD 1.3 YEARS
NWOSU, DIXON
93
IJEH, ISIJOKELU
A3
Water Injection Injec tion:: Evalua Ev aluation tion Of Revenue Re venue,, Opex, Ope x, Cash Ca sh Flow, F low, Internal Intern al Rate R ate Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor WATER WATER I NJECTION NJECTION Oil Price = $110/bbl Dis c. rate= 10% Producti Producti on in on in Cash 3 MMm CAPEX Revenue Depr OPEX Income Income Tax Bill Flow low Year Disc. bbls 0
1
0
0
1
0. 0.91
16 .214
2
0. 0.83
3 4
1 04 6
0
0
0
0
-1046
-1046
2.578
1783.5 69.733
1 05
16 1608.4
643.4
9 65
877.3
-168 .7
16 .528
2.628
1818.1 69.733
1 07 07
16 1640.9
656.4 984 .6
813.7
64 5
0. 0.75
16 .572
2.635
1823 69.733
1 08 08
16 1645.5
658.2 987 .3
741.8
13 1386.8
0. 0.68
16 .572
2.635
1823 69.733
1 08 08
16 1645.5
658.2 987 .3
674.3
20 2061.1
5 0 .6 .62
13 .358
2.124
1469.4 69.733 86.8 1 31 312.9
525.1 787.7
489.1 2 55 550 .2
6 0 .5 .56
9.1006
1.447
1001.1 69.733 59.2 8 72 72 .18
348.9 523.3
295.4 2 84 845 .6
7 0 .5 .51
6.4843
1.031
713.27 69.733 42.1 6 01 01 .39
240.6 360.8
185.2 3 03 030 .8
8 0 .4 .47
5.1384
0.817
565.22 69.733 33.4 4 62 62 .09
184.8 277.3
129.3 3 16 160 .1
9
0. 0.42
4.1258
0.656
453.84 69.733 26.8
35 357 .29
142.9 214.4
90.91
10 0 .3 .39
3.2704
0 .52
359.75 69.733 21.3 2 68 68 .76
107.5 161.3
62.17 3 31 313 .2
11
0. 0.35
2.6415
0 .42
290.57 69.733 17.2
81 .47 122.2
42.83
12 0 .3 .32
1.9748
0.314
217.23 69.733 12.8 1 34 34 .66
53 .87
25.74 3 38 381 .8
13
0. 0.29
1.2579
0.2
138.36 69.733 8 .18
60 60.455
24 .18 36.27
10 .51
33 3392.3
14
0. 0.26
1 .195
0 .19
131.45 69.733 7 .77
53 53.946
21 .58 32.37
8.523
34 3400.8
15 0 .2 .24
1.0692
0 .17
117.61 69.733 6 .95 4 0. 0.927
16 .37 24.56
5.879 3 40 406 .7
20 203 .66
0 -1046
NPV
Cum.NP V
I RR
80.8
3 25 1 3 35 6
9 0%
PAYBACK PAYBACK PERIO D 1.2 YEARS
NWOSU, DIXON
94
IJEH, ISIJOKELU
A4 Natural Natu ral Depletion: Deple tion: Evaluatio Eval uation n Of Revenue, Reven ue, Opex, Cash Flow, Internal Inter nal Rate Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor WAG INJECTION Oil Price = $110/bbl
Disc. rate= 10% Producti Producti on in on in MMm3 CAPEX Revenue Depr OPEX Income Income Tax Bill Year Year Di sc. bbls
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15
1 0.9 0.91 1 0.8 0.83 3 0.7 0.75 5 0.6 0.68 8 0.6 0.62 2 0.5 0.56 6 0.5 0.51 1 0.4 0.47 7 0.4 0.42 2 0.3 0.39 9 0.35 .35 0.3 0.32 2 0.2 0.29 9 0.26 .26 0.2 0.24 4
0 15.59 .597 16.34 .34 17.00 .006 16.46 .465 14.84 .843 10.89 .893 7.20 .2075 5.59 .5912 4.23 .2327 2.90 .9057 2.56 .566 2.24 .2453 2.23 .239 1.88 .8868 1.72 .7296
NWOSU, DIXON
0 2.48 .48 2.59 .598 2.70 .704 2.61 .618 2.36 .36 1.73 .732 1.14 .146 0.88 .889 0.67 .673 0.46 .462 0.40 .408 0.35 .357 0.35 .356 0.3 0.27 .275
1090
0 1715.7 1797.4 1870.7 1811.2 1632.7 1198.2 792.83 .83 615.03 .03 465.6 319.62 .62 282.26 .26 246.98 .98 246.29 .29 207.55 .55 190.25 .25
0 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68 72.68 .68
95
0 101 106 111 107 96.5 70.8 46.8 36.3 27.5 18.9 16.7 14.6 14.6 12.3 11.2
0 15 1541.7 16 1618.5 16 1687.5 16 1631.5 14 1463.5 1054.8 673.3 506.01 .01 365.4 22 228.06 .06 192.9 15 159.71 .71 15 159.06 .06 122.6 10 106.33 .33
0 616.66 .664 64 647.38 .388 67 674.98 .988 65 652.59 .596 58 585.41 .419 42 421.90 .902 269.32 .32 20 202.40 .403 146.16 .162 91 91.22 .2223 77.16 .162 63 63.88 .8827 63 63.62 .6223 49.04 .0412 42 42.53 .5318
Cash Fl ow
NPV
-1090.2 -1090.2 924.99 .996 840.90 .905 971.08 .083 802.54 .548 1012.48 .48 760.69 .693 978.89 .894 668.59 .598 878.12 .128 545.24 .248 632.85 .852 357.22 .229 403 403.98 .981 207.30 .306 303.60 .605 141.63 .634 219 219.24 .243 92.98 .9804 136.83 .834 52.75 .7552 115 115.74 .743 40.56 .5672 95.82 .8241 30.53 .5325 95.43 .4335 27 27.64 .6437 73.5 73.56 618 19.37 .3711 63.79 .7977 15.27 .2727 IRR 85% PAYBACK PERIOD
Cum.NP V
-1090 -24 -249.3 55 553.25 .25 13 1313.9 19 1982.5 25 2527.8 2885 30 3092.3 3234 33 3326.9 33 3379.7 3420.3 34 3450.8 34 3478.4 3497.8 35 3513.1 I.3 YEARS
IJEH, ISIJOKELU
APPENDIX B Evaluation Of Npv For The Various Development Schemes Using The Calculated Calculated Internal Rate Of Return B1 Gas Injection: Evaluation Of Npv Using The Calculated Internal Rate Of Return GAS INJECTION Oil Price = $110/bbl Di s c. Ra te te
0 .8 4 68
Prod. in
Prod. in Yea Yea Disc. F bbls
3
MMm
Tax Bill
CAPEX Revenue Depr OPEX Income
0
1
0
0
1
0. 0 .5 41
1 6. 16 3 52 2
2
0 .2 .2 93 93
3
NPV
Cum.NP V
0
0
0
0
0
-10 9 0. 2
-1 09 0 .2
-10 9 0. 2
2. 57
1 7 77 .9 9
7 2. 68
10 105 .0 6
1 6 00 .2 4 5
64 6 40 .1
96 96 0. 14 6 7
51 9 .8 97 5
-5 7 0. 3
1 6. 6. 76 76 10 100 6
2 .6 .6 65 65
1 84 843 .7 .7 1
6 9. 9. 48 48
10 108 .9 .9 5
1 66 665 .2 .2 84 84
6 66 66 .1 .1
99 99 9. 9. 17 17 05 05
29 2. 2.9 54 54 3
-27 7. 7.3 5
0 .1 .1 59 59
1 6. 6. 38 38 99 993 7
2 .6 .6 06 06
1 80 802 .8 .8 9
6 9. 9. 48 48
10 106 .5 .5 3
1 62 626 .8 .8 78 78
6 50 50 .8 .8
97 97 6. 6. 12 12 71 71
15 4. 4.9 69 69 7
-12 2. 2.3 8
4
0 .0 .0 86
1 6. 56 6 03 8
2 .6 34
1 8 22 .2 6
6 9. 48
10 107 .6 8
1 6 45 .1 0 5
658
98 98 7. 06 2 9
84 .8 5 26 4
-37 .5 2 6
5
0 .0 .0 47
8 .8 67 9 24 5
1. 41
9 7 5. 47 2
6 9. 48
57 57. 64 2
8 4 8. 35 0 2
3 39 39 .3
50 50 9. 01 0 1
23 .6 9 33 8
-13 .8 3 2
6
0 .0 .0 25 25
6 .6 .6 35 35 22 220 1
1 .0 .0 55 55
7 29 29. 87 87 4
6 9. 9. 48 48
43 43. 12 12 9
6 17 17. 26 26 53 53
2 46 46 .9 .9
37 37 0. 0. 35 35 92 92
9. 33 33 47 477 6
-4. 49 49 77 77
7
0 .0 .0 14 14
4 .2 .2 64 64 15 150 9
0 .6 .6 78 78
4 69 69. 05 05 7
6 9. 9. 48 48
27 27. 71 71 7
3 71 71. 85 85 96 96
1 48 48 .7 .7
22 22 3. 3. 11 11 58 58
3. 04 04 50 502 7
-1. 45 45 27 27
8
0. 0 .0 08
2 .7 67 2 95 6
0. 44
3 0 4. 40 3
6 9. 48
17 17. 98 7
2 1 6. 93 5 1
86 8 6. 77
13 13 0. 16 1 1
1 .0 8 12 1
-0. 37 1 5
9
0 .0 .0 04
1 .8 11 3 20 8
0 .2 88
1 9 9. 24 5
6 9. 48
11 11. 77 4
1 1 7. 99 1 7
4 7.2
70 70 .7 95 0 2
0. 28 3 28 5
-0. 08 8 2
10
0. 0.0 02 02
1 .1 .1 50 50 94 943 4
0 .1 .1 83 83
1 26 26. 60 60 4
6 9. 9. 48 48
7. 7.4 81 81 1
4 9. 9.6 42 42 64 64
1 9. 9. 86 86
29 29 .7 .7 85 85 58 58
0. 06 06 45 453 7
-0. 02 02 36 36
11
0. 0.0 01 01
0 .9 .9 87 87 42 421 4
0 .1 .1 57 57
1 08 08. 61 61 6
6 9. 9. 48 48
6. 6.4 18 18 2
3 2. 2.7 18 18 11 11
1 3. 3. 09 09
19 19 .6 .6 30 30 87 87
0. 02 02 30 303 1
-0. 00 00 06 06
12
6 EE-04
0 .0 .0 62 62 89 893 1
0. 01 01
6 .9 .9 18 182 4
6 9. 9. 48 48
0. 0.4 08 08 8 -6 2. 2.9 70 70 57 57 -2 5. 5. 19 19
-3 7. 7. 78 78 23 23 -0. 02 02 40 400 2
-0. 02 02 46 46
13
3E-04
0
0
0
6 9. 48
0
-69 .4 8 -2 7. 79
-41 .6 8 8
-0 .0 1 43 4
-0 .0 3 9
14
2E-04
0
0
0
6 9. 48
0
-69 .4 8 -2 7. 79
-4 -41 .6 8 8 -0. 00 7 76 5
-0. 04 6 7
15
1E-04
0
0
0
6 9. 48
0
-69 .4 8 -2 7. 79
-4 -41 .6 8 8 -0. 00 4 20 4
-0. 05 0 9
NWOSU, DIXON
1 09 0
Cash Fl ow
96
IJEH, ISIJOKELU
B2 Water Injection: Evaluation Of Npv Using The Calculated Internal Rate Of Return WATER INJECTION Oil Price Price = $110/bbl $110/bbl D i sc s c. R a te te
0.904
Annual Producti Annual Production on in 3 MMm Yea Disc. F in bbls 0
Depre ciatio CAPEX Revenue n OPEX 0
0
Taxable Income 0
0
-1 - 1046
- 1046
Net Present value
0
0
1 0.52 0.525 5
16. 16.2138 213836 36
2.57 2.578 8
1783 1783.5 .52 2
69. 69.73 105 105.39 .39
1608 1608.3 .399 99 643 643.4 .4 965. 965.03 0392 92 506. 506.84 848 83
-539 -539..15
2 0.27 0.276 6
16. 16.5283 528302 02
2.62 2.628 8
1818 1818.1 .11 1
69. 69.48 107 107.43 .43
1641 1641.1 .199 99 656 656.5 .5 984. 984.71 7195 95 271. 271.63 630 06
-267 -267..52
3 0.14 0.145 5
16. 16.5723 572327 27
2.63 2.635 5
1822 1822.9 .96 6
69. 69.48 107 107.72 .72
1645 1645.7 .756 56 658 658.3 .3 987. 987.45 4535 35 143. 143.05 059 92
-124 -124..46
4 0.07 0.076 6
16. 16.5723 572327 27
2.63 2.635 5
1822 1822.9 .96 6
69. 69.48 107 107.72 .72
1645 1645.7 .756 56 658 658.3 .3 987. 987.45 4535 35 75.1 75.136 361 14
-49. -49.3 326
0.04 13. 13.358491
2.124
1469.43
69.48
1313.124 52 525.2 787.8743
31.48634
-17 -17.839
86.83
0
Net Present Value
1
5
1046
Tax Bill of the Projec Cash t Flow
- 1046
6 0.0 0.021
9.1006289
1.447
1001.07
69.48 59 59.154
872.4351
349 52 523.4611
10.98709
-6. -6.8523
7 0.0 0.011
6.4842767
1.031
713.27
69.48 42 42.148
601.6426 240 240.7 36 360.9856
3.979433
-2. -2.8729
8 0.0 0.008
5.1383648
0.817
565.22
69.48 33 33.399
462.3408 184 184.9 27 277.4045
2.304318
-0. -0.5685
9 0. 0.003 4.1 4.1257862
0.656
453.836 69. 69.48 26.818
143 214.5233 0.6 0.652337
0.0838
357.5389
10 0. 0.002 002
0.32 0.3270 7044 44
0.05 0.052 2
35. 35.974 9748
69. 69.48 2.12 2.125 58 -35. -35.63 6309 094 4
-14. -14.3 3
-21 -21.378 .3786 6 -0.0 -0.034 341 144 0.04 0.0496 966 6
11 8E-0 E-04
0.26 0.264 41509 1509
0.04 0.042 2
29. 29.056 0566
69. 69.48
1.71 1.717 7 -42. -42.14 1403 038 8
-16. -16.9 9
-25 -25.284 .2842 2 -0.0 -0.021 212 209 0.02 0.0284 845 5
12 4E4E-0 04
0.19 0.197 74843 4843
0.03 0.0314 14
21. 21.723 7233
69. 69.48 1. 1.283 2836 -49 -49..0403 04038 8
-19. -19.6 6
-29 -29.424 .4242 2 -0.0 -0.012 129 963 0. 0.0154 01549 9
13 2E2E-0 04
0.01 0.012 25786 5786
0.00 0.002 2
1.3 1.3836 8365
69. 69.48 0.08 0.081 18 -68. -68.17 1781 811 1
-27. -27.3 3
-40 -40.906 .9069 9 -0.0 -0.009 094 465 0. 0.0060 00602 2
14 1E1E-0 04
0.01 0.011 19497 9497
0.00 0.0019 19
1.3 1.3144 1447
69. 69.48 0. 0.077 0777 -68 -68..2432 24321 1
-27. -27.3 3
-40 -40.945 .9459 9 -0.0 -0.004 049 976 0. 0.0010 00104 4
15 6E6E-0 05
0.0106918
0.0017
1.1761
69.48 0. 0.0695
-27 -27.3
NWOSU, DIXON
97
-68 -68.3734
-41 -41.024 -0. -0.002618
-0. -0.0016
IJEH, ISIJOKELU
B3 Wag Injection: Evaluation Of Npv Using The Calculated Internal Rate Of Return WAG INJECTION Oil Price Price = $110/bbl $110/bbl Di sc. sc. Rate Rate
0.8181 Prod. Prod. i n
Prod. Prod. in bbls Year Dis c. F 0
1
3
MMm 0
Cash Fl o w
CAPEX Revenue Depr OPEX Income Income Tax Bill 0 1090.2
0
0
0
0
0
NPV
-1090.2
Cum.NP V
- 1090.2
-1090.2
1 0.549 15.59748
2.48
1715.72
72.68
101 15 1541.66 616 616.6638 924.99577 50 508.2394
- 58 581.96
2 0.30 .303 16.3 16.33 3962
2.59 .598
1797 797.36 .36
72.68 .68
106 106
29 293.77 .7789
-28 -288.1 8.18
3 0.166 12.83019
2.04
1411.32
72.68
83.4 12 1255.24
502.0978 753.14672 1 12 25 5.3217
- 16 162.86
4 0.09 .092 16.4 16.46 6541
2.61 .618
1811 811.19 .19
72.68 .68
107 107
16 1631.4 31.49 9
652 652.59 .5959 978.8 8.89389
89 89.59 .59103
-73 -73.26 .269
0.05 14.84277
2.36
1632.7
72.68
96. 96.5 1463.55
58 585.4186 878.12785
44 44.20475
- 29 29.06 .064
6 0.02 .028 10.8 10.89 9308
1.73 .732
1198 198.24 .24
72.68 .68
70.8 70.8 1054.7 54.75 5 421 421.90 .9016 632.8 2.85238 17 17.52 .52249 -11.5 -11.54 42
7 0.015 7.207547
1.146
792.83
72.68
46.8 67 673.301
269.3205 403.98068 6.1 6.152282
- 5. 5.3894
8 0.008 5.591195
0.889
615.031
72.68
36.3 50 506.009
202.4035 303.60521
2.52196
- 2. 2.8674
9 0.005 4.232704
0.673
465.597
72.68
27.5 36 365.405
146.162 219.24294 1.0 1.010103
- 1. 1.8573
2.90 .90566
0.46 .462
319.6 19.62 23
72.68 .68
18.9 18.9 228.0 8.056
11 0.00 .001 2.5 2.566038
0.40 .408
282.2 82.26 64
72.68 .68
16.7 16.7 192.9 2.905 77.1 77.16 6196 115.7 5.74294 0.1 0.16 61324 -1.3 -1.3493 493
12 8E-0 8E-04 4 2.2 2.245283
0.35 .357
246.9 46.98 81
72.68 .68
14.6 14.6 15 159.7 9.707
63.88 .88272 95.82 .824075 0.0 0.073462
-1.2 -1.275 758 8
13 4E-0 4E-04 4 2.2 2.238994
0.35 .356
246.2 46.28 89
72.68 .68
14.6 14.6 15 159.0 9.056
63.62 .62234 95.43 .433509 0.0 0.040241
-1.2 -1.235 356 6
14 2E- 04 04 1.886792
0.3
207.547
72.68
12.3 12 122.603 4 49 9..04121 73.56 .561811 0. 0.017061
- 1. 1.2185
0.275
190.252
72.68
11.2 10 106.329 4 42 2..53177
- 1. 1.2104
5
10 0.00 .003
15 1E- 04 04
1.72956
NWOSU, DIXON
98
16 1618.4 18.47 7
647 647.38 .3884 971.0 1.08257
91.2 91.22 2234 136.8 6.83351
0.3 0.34 46749
63.79 .79766 0. 0.008138
-1.5 -1.510 106 6
IJEH, ISIJOKELU
APPENDIX C Full PVT Report
-- Maximum Simulation Pressure PMAX 550 418 1* 1* /
--- ++++++++++++++++++++ WATER +++++++++++++++++++++++++++++ --- ++++++++++++++++++++ W,O,G Gravity ++++++++++++++++++++++ --PVTW
ECHO -- DENSITY created by PVTi -- Units: kg /m^3 kg /m^3 kg /m^3 DENSITY --- Fluid Densities at Surface Conditions -829.7675 1020.0000 1.0449 / NWOSU, DIXON
99
IJEH, ISIJOKELU
-- Column Properties are: -'Oil RS' 'PSAT' 'Oil FVF' 'Oil Visc' -- Units: sm3 /sm3 bar rm3 /sm3 cp PVTO --- Live Oil PVT Properties (Dissolved Gas) -0.0000 1.0132 1.0463 3.6674 25.0000 1.0450 3.7326 50.0000 1.0436 3.7990 100.0000 1.0411 3.9272 150.0000 1.0387 4.0495 175.0000 1.0377 4.1086 200.0000 1.0366 4.1665 225.0000 1.0356 4.2231 250.0000 1.0346 4.2784 258.2362 1.0343 4.2964 300.0000 1.0328 4.3858 350.0000 1.0310 4.4888 375.0000 1.0302 4.5387 400.0000 1.0294 4.5877 409.1537 1.0291 4.6054 413.7306 1.0290 4.6142 418.3074 1.0289 4.6230 450.0000 1.0279 4.6828 500.0000 1.0265 4.7743 550.0000 1.0251 4.8625 / 18.5139 25.0000 1.1266 1.2536 50.0000 1.1213 1.3220 100.0000 1.1119 1.4561 150.0000 1.1038 1.5868 NWOSU, DIXON
100
IJEH, ISIJOKELU
175.0000 1.1001 1.6509 200.0000 1.0966 1.7142 225.0000 1.0934 1.7767 250.0000 1.0903 1.8384 258.2362 1.0893 1.8585 300.0000 1.0846 1.9595 350.0000 1.0794 2.0775 375.0000 1.0771 2.1355 400.0000 1.0748 2.1927 409.1537 1.0740 2.2135 413.7306 1.0736 2.2238 418.3074 1.0732 2.2341 450.0000 1.0705 2.3050 500.0000 1.0666 2.4145 550.0000 1.0630 2.5213 / 35.3469 50.0000 1.1813 1.0227 100.0000 1.1695 1.1400 150.0000 1.1595 1.2548 175.0000 1.1550 1.3114 200.0000 1.1507 1.3673 225.0000 1.1468 1.4227 250.0000 1.1430 1.4774 258.2362 1.1418 1.4954 300.0000 1.1362 1.5853 350.0000 1.1300 1.6909 375.0000 1.1271 1.7428 400.0000 1.1244 1.7942 409.1537 1.1235 1.8128 413.7306 1.1230 1.8222 418.3074 1.1225 1.8314 450.0000 1.1193 1.8953 500.0000 1.1147 1.9942 NWOSU, DIXON
101
IJEH, ISIJOKELU
550.0000 1.1104 2.0910 / 67.7343 100.0000 1.2798 0.7137 150.0000 1.2651 0.8008 175.0000 1.2586 0.8439 200.0000 1.2525 0.8868 225.0000 1.2469 0.9294 250.0000 1.2417 0.9718 258.2362 1.2400 0.9856 300.0000 1.2321 1.0555 350.0000 1.2237 1.1381 375.0000 1.2198 1.1790 400.0000 1.2161 1.2195 409.1537 1.2147 1.2343 413.7306 1.2141 1.2417 418.3074 1.2135 1.2490 450.0000 1.2092 1.2997 500.0000 1.2030 1.3786 550.0000 1.1973 1.4562 / 103.9068 150.0000 1.3865 0.5143 175.0000 1.3772 0.5464 200.0000 1.3686 0.5785 225.0000 1.3607 0.6105 250.0000 1.3534 0.6424 258.2362 1.3511 0.6529 300.0000 1.3403 0.7060 350.0000 1.3287 0.7690 375.0000 1.3235 0.8004 400.0000 1.3185 0.8316 409.1537 1.3168 0.8430 413.7306 1.3159 0.8487 418.3074 1.3151 0.8543 450.0000 1.3094 0.8936 NWOSU, DIXON
102
IJEH, ISIJOKELU
500.0000 1.3012 0.9549 550.0000 1.2937 1.0156 / 124.0654 175.0000 1.4453 0.4401 200.0000 1.4350 0.4677 225.0000 1.4256 0.4952 250.0000 1.4170 0.5227 258.2362 1.4143 0.5318 300.0000 1.4015 0.5776 350.0000 1.3881 0.6322 375.0000 1.3820 0.6595 400.0000 1.3763 0.6866 409.1537 1.3743 0.6965 413.7306 1.3733 0.7015 418.3074 1.3723 0.7065 450.0000 1.3657 0.7407 500.0000 1.3563 0.7943 550.0000 1.3477 0.8476 / 146.0774 200.0000 1.5092 0.3782 225.0000 1.4980 0.4017 250.0000 1.4877 0.4253 258.2362 1.4845 0.4330 300.0000 1.4695 0.4724 350.0000 1.4538 0.5195 375.0000 1.4467 0.5430 400.0000 1.4400 0.5665 409.1537 1.4376 0.5751 413.7306 1.4365 0.5794 418.3074 1.4354 0.5837 450.0000 1.4278 0.6134 500.0000 1.4169 0.6600 550.0000 1.4071 0.7064 / 170.3161 225.0000 1.5795 0.3260 NWOSU, DIXON
103
IJEH, ISIJOKELU
250.0000 1.5672 0.3461 258.2362 1.5634 0.3527 300.0000 1.5456 0.3864 350.0000 1.5271 0.4267 375.0000 1.5188 0.4469 400.0000 1.5110 0.4672 409.1537 1.5083 0.4746 413.7306 1.5069 0.4783 418.3074 1.5056 0.4820 450.0000 1.4968 0.5076 500.0000 1.4842 0.5479 550.0000 1.4729 0.5882 / 197.2831 250.0000 1.6576 0.2819 258.2362 1.6530 0.2875 300.0000 1.6318 0.3161 350.0000 1.6099 0.3505 375.0000 1.6001 0.3678 400.0000 1.5910 0.3851 409.1537 1.5878 0.3914 413.7306 1.5863 0.3946 418.3074 1.5847 0.3978 450.0000 1.5745 0.4197 500.0000 1.5599 0.4544 550.0000 1.5469 0.4891 / 206.8974 258.2362 1.6855 0.2688 300.0000 1.6629 0.2959 350.0000 1.6398 0.3285 375.0000 1.6294 0.3449 400.0000 1.6198 0.3613 409.1537 1.6165 0.3673 413.7306 1.6148 0.3703 418.3074 1.6132 0.3733 NWOSU, DIXON
104
IJEH, ISIJOKELU
450.0000 1.6024 0.3942 500.0000 1.5871 0.4271 550.0000 1.5734 0.4601 / 262.4248 300.0000 1.8468 0.2119 350.0000 1.8154 0.2364 375.0000 1.8016 0.2488 400.0000 1.7888 0.2612 409.1537 1.7843 0.2658 413.7306 1.7822 0.2681 418.3074 1.7800 0.2704 450.0000 1.7659 0.2862 500.0000 1.7458 0.3114 550.0000 1.7281 0.3367 / 352.8457 350.0000 2.1123 0.1584 375.0000 2.0917 0.1670 400.0000 2.0728 0.1756 409.1537 2.0663 0.1788 413.7306 2.0631 0.1804 418.3074 2.0599 0.1820 450.0000 2.0393 0.1930 500.0000 2.0105 0.2106 550.0000 1.9853 0.2284 / 418.4723 375.0000 2.3092 0.1347 400.0000 2.2851 0.1417 409.1537 2.2769 0.1443 413.7306 2.2728 0.1456 418.3074 2.2688 0.1468 450.0000 2.2429 0.1558 500.0000 2.2069 0.1701 550.0000 2.1756 0.1846 / 516.4766 400.0000 2.6103 0.1112 409.1537 2.5991 0.1132 NWOSU, DIXON
105
IJEH, ISIJOKELU
413.7306 2.5936 0.1142 418.3074 2.5883 0.1152 450.0000 2.5534 0.1221 500.0000 2.5055 0.1332 550.0000 2.4644 0.1445 / 572.8376 409.1537 2.7881 0.1015 413.7306 2.7817 0.1024 418.3074 2.7755 0.1032 450.0000 2.7351 0.1094 500.0000 2.6798 0.1193 550.0000 2.6326 0.1293 / 611.3386 413.7306 2.9115 0.0959 418.3074 2.9046 0.0968 450.0000 2.8603 0.1025 500.0000 2.7998 0.1116 550.0000 2.7483 0.1209 / 665.6448 418.3074 3.0883 0.0893 450.0000 3.0382 0.0945 500.0000 2.9700 0.1028 550.0000 2.9124 0.1113 / /
-- Column Properties are: -- 'Pressure' 'Gas FVF' 'Gas Visc' -- Units: bar rm3 /sm3 cp PVDG --- Dry Gas PVT Properties (No Vapourised Oil) -1.0132 1.3262 0.0109 25.0000 0.0505 0.0126 NWOSU, DIXON
106
IJEH, ISIJOKELU
50.0000 0.0247 100.0000 0.0121 150.0000 0.0080 175.0000 0.0069 200.0000 0.0061 225.0000 0.0056 250.0000 0.0051 258.2362 0.0050 300.0000 0.0045 350.0000 0.0040 375.0000 0.0039 400.0000 0.00373 409.1537 0.00372 413.7306 0.00371 418.3074 0.0036
NWOSU, DIXON
0.0136 0.0153 0.0175 0.0189 0.0203 0.0217 0.0232 0.0237 0.0261 0.0289 0.0302 0.0314 0.0319 0.0321 0.0324/
107
IJEH, ISIJOKELU
