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Group 6Abdul Afif Osman 12501Elisha Md Talip 12564Harun Abd Rahman 12979
Mohamed Yousry Ahmed Hussien 12279 Mohd Ridzuan Hamid 12688
Muhammad Afdhaludden Azmi 12712Muhammad Haidir Nizam Baharuddin 12736Norsyuhada Abd Razak 12796
Final PresentationField Development Plan
PRESENTATION OUTLINE
INTRODUCTION GEOLOGY & GEOPHYSICS PETROPHYSICS RESERVOIR
CONCLUSION &
RECOMMENDATION
CHAPTER 1: INTRODUCTION
• Backgroud of Study• Problem Statement• Objectives• Gantt Chart
• The field development plan of Gulfaks Field covers: Geology, Geophysics &Petrophysics Reservoir Engineering Development Plan
• The main Gulfaks field lies in block 34/10 in the northern part of Norwegian sector, discovered in 1979.
BACKGROUND OF STUDY
Gulfaks Reservoir
Middle Jurassic Sandstones Brent Formation
Lower Jurassic & Upper Triassic
Sandstones
Cook Formation
Statfjord Formation
Lunde Formation
BACKGROUND OF STUDY
• The Gullfaks reservoirs are located in rotated fault blocks in the west and a structural horst in the east, with a highly faulted area in-between.
• Exploration and production phases were completed by the end of 1983 with 14 wells had been drilled into structure. Exploration results are evaluated as follows: Number of successful wells – 10 Number of dry wells – 3 Abandoned wells – 1.
• This field development plan focused on surfaces from Brent Group that consist of : Base Cretaceous Top Tabert Top Nest Top Etive
PROBLEM STATEMENT
The Gullfaks field was discovered in 1979, and since then, further study has
been conducted with gathering of information from three production platforms
Gulfaks A, Gulfaks B and Gulfaks C. Due to the complexity of the Gulfaks field,
time constraint, limited data and large number of uncertainties, the determination
of the best development options has been considered as a tough challenge.
OBJECTIVES
To carry out a technical and economics study of the proposed development utilizing the latest technology available.
Objectives in formulating the best, possible FDP will include the following: • Maximizing economic return• Maximizing recoverable hydrocarbons • Maximizing hydrocarbon production • Providing recommendations in reducing risks and uncertainties• Providing sustainable reservoir production planning.
GANTT CHART
ACTIVITY/WEEK 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16FDP Briefing G&G Phase Reservoir Engineering Phase Report submission Oral presentation
CHAPTER 2: GEOLOGY & GEOPHYSICS
• Geological setting• Reservoir geology• Static modeling• Fluid contacts• Reservoir Mapping• Volumetric Calculation
Geological setting• Situated on the western flank of Viking
Graben• Approximately 175 km northwest of
Bergen• The field is related to block 34/10 and
covers an area of 55 km2 and occupies the eastern half of the 10-25 km wide Gullfaks fault block (Fossen and Hesthammer, 2000).
• Gullfaks represents the shallowest structural element of the Tampen spur
• Formed during the Upper Jurassic to Lower Cretaceous
GEOLOGICAL SETTING
Regional position of the Northern North Sea and the study area
Geological setting
• The field produces from three separate CBS platforms, the Gullfaks A, B and C.
• Gullfaks A and C are fully independent processing platforms with three separation stages.
GEOLOGICAL SETTING
Reservoir Geology
• This petroleum system consist of sandstones, siltstones, shales and coals
• The thickness distribution of reservoir rock is consequently controlled by both the thermally driven subsidence and ongoing faulting of the Late Jurassic-Early Cretaceous episode of rifting.
RESERVOIR GEOLOGY
Reservoir geologyThree structural region of Gullfaks field:
DOMINO COMPLEX
ACCOMMODATION ZONE
HORST COMPLEX
• Main part of Gullfaks field
• The deformation caused north-south trending blocks
• Transition between domino and horst
• It is a graben structure
• Faults steeper than domino complex
• Sub horizontal bedding
RESERVOIR GEOLOGY
Reservoir Geology
• subdivided into 5 major stratigraphic units:– Broom Formations– Rannoch Formations– Etive Formations – Ness Formations (lower
& upper ness)– Tarbert Formations.
RESERVOIR GEOLOGY
Static Modelling STATIC MODELLING
• Making surface, exaggeration & horizons• Defining well tops• Zonation & layering
Structural Modelling
• Scale-up well logs• Petrophysical modelling
Property Modelling
• MDT Formation Pressure Plot• Resistivity log
Fluid Contacts
Volumetric Calculation
Uncertainty & Optimization
1
2
3
4
Base Cretaceous
2) Defining exaggeration
Top Tarbert
Top Ness
Top Etive
Structural Modelling
1) Making surface
STATIC MODELLING
Base Cretaceous
Structural Modeling STATIC MODELLING
3) Defining well tops
4) Zonation & layering
Structural Modelling
Structural model of Gullfaks
STATIC MODELLING
Structural Modelling
Skeletal structure model of Gullfaks
STATIC MODELLING
Property Modelling of Porosity Model
« SCALLING-UP POROSITY LOGS• averages the values to the cells in the
3D grid• Gives the cell one single value per up-
scaled porosity log
PETROPHYSICAL MODELLING OF POROSITY• the values for each cell along the well
trajectory are interpolated between the wells in the 3D grid
• resulting a 3D model of porosity
»»
Property Modelling of Permeability Model
« SCALLING-UP PERMEABILITY LOGS• averages the values to the cells in the
3D grid• Gives the cell one single value per up-
scaled permeability log
PETROPHYSICAL MODELLING OF PERMEABILTIY• the values for each cell along the well
trajectory are interpolated between the wells in the 3D grid
• resulting a 3D model of permeability
»»
TVD (ft) Formation Pressure (psia)
5513.32 2434.898
5543.537 2435.288
5570.702 2435.398
5597.772 2443.478
5629.809 2450.203
5656.103 2453.979
5683.301 2459.723
5757.054 2476.955
5803.642 2487.335
5846.358 2498.208
5869.652 2506.643
5922.769 2517.516
5951.148 2526.843
5978.347 2540.094
6017.159 2545.354
Gas-Oil Contact (GOC)• Using data of well A10• 1697.95 m (5570.70 ft)
FLUID CONTACTFluid Contacts using MDT Formation Pressure Plot
Fluid Contacts using MDT Formation Pressure Plot
TVD (ft) Formation Pressure (psia)
5725.131 2473.813
5748.032 2478.272
5780.709 2490.318
5829.757 2502.174
5865.748 2512.031
5927.395 2524.744
5996.063 2540.458
6068.012 2558.431
6113.78 2569.271
6228.904 2602.928
6250.148 2607.001
6267.143 2615.181
6288.075 2623.611
Oil-Water Contact (OWC)• Using data of well B9• 1905.05 m (6250.15 ft)
FLUID CONTACTFluid Contacts using MDT Formation Pressure Plot
Fluid Contacts using Resistivity Log
Oil-Water Contact (GOC)
• In support of MDT pressure plot data
• Using log of well A20• At depths before 1900 m, the
resistivity is in a large range reaching 200 ohm at most
• The resistivity decreases with depth and become nearly constant after the depth of 1900 m (0.5~5 ohms)
• Reduction of resistivity indicates the increase of water saturation
• Resistivity log concurs with MDT pressure plot data
• OWC = 1905.05 m
Fluid Contacts using MDT Formation Pressure PlotFLUID CONTACTFluid Contacts using resistivity log
Fluid Contacts 3D Model
Fluid Contact model from
Above
FLUID CONTACT 3D MODEL
Cross-section of Fluid Contacts model
Cross-sectional model of Fluid Contacts (east-west)
FLUID CONTACT
Reservoir Mapping
A
B
C
D
Figure 1: Base Cretaceous surface map with cross section line
Horizontal Cross Section
Vertical Cross Section
RESERVOIR MAPPING
2 Dimensional Imaging
GOC1697m
WOC1905m
Zone 1Zone 2
Zone 3Zone 4
Zone 5
Base CretaceousTop Talbert
Top NessTop etive
Horizontal Cross Section B8, B9, C5 and C6
RESERVOIR MAPPING
Vertical Cross Section A15, B9 and C3
WOC1905m
GOC1697m
Zone 1Zone 2
Base CretaceousTop Talbert
Top NessTop etive
RESERVOIR MAPPING
VOLUMETRIC CALCULATION
• The STOIIP and GIIP are calculated in Petrel to have more accurate estimation
• The other constant value required such as Sw, So, Ø and Bg are calculated based on SCAL report. The result is tabulated below
Setting up hydrocarbon interval
Sw So Bg Bo NTG
0.2591 0.7535 0.0056 1.1 0.69
VOLUMETRIC CALCULATION
From Petrel From Statoil Report (31.12.2012)
From report by Terra 3ESAS
STOIIP [mill sM3] 397 396.93 383
GIIP [bill sM3] 80.6 80.1 -
CHAPTER 3: PETROPHYSICS
• Log Correlation
LOG CORRELATION
Basis of Petrophysical correlation is derived from vertical cross section of wells through 2D Cross Imaging
Each well represents each platform – A, B and C
Findings are validated using:1. Gamma Ray Log2. Porosity Log3. Permeability Log
LOG CORRELATION
A15 (%) B9 (%) C3 (%)
Silt 25.6 21.1 28.0
Fine Silt 12.0 24.6 15.3
Sandstone 47.9 46.4 30.0
Shale 14.5 7.9 26.7
Well A 15 can be produced all the way from the Top Ness to Top Etive layer from the depth 1810 – 1925 ft. These layers show high thickness of hydrocarbon bearing sandstone at a range from 40% to 69%.
Similarly, Well B9 can be produced from the Top Ness to Top Etive layer from the depth 1840 – 1880 ft. The aforementioned depths are the only producible zones in this well and this is verified by the high amount of sandstone at 91%.
None of the layers in well C5 is suitable for production as it is made up of mostly shale and siltstone.
CHAPTER 4: RESERVOIR
• Reservoir Engineering• Reservoir Characteristic• Fluid Studies• SCAL• Reservoir simulation study
Reservoir Engineering Section (Intro)
• Develop Gullfaks Field with most feasible, profitable and sustainable reservoir production planning
• Studies of reservoir engineering aspects are focused on analysing reservoir production performance, under current and future operating conditions
• Well test data, PVT and SCAL report is used for analysis• Main output:
1) Drive Mechanisms 2) Well locations and number of wells
3) Production Profile 4) Recovery Profile
5) EOR Considerations
Reservoir Engineering (Intro)
Reservoir Characteristics• 6 Zones:
Base Cretaceous – Top Tarbert
Tarbert 1 – Tarbert 2
Top Tarbert – Tarbert 1
Ness 1 – Top Etive
Top Ness – Ness 1
Tarbert 2 – Top Ness
Zones which have possible amount of oil to be recovered
Top Tarbert- Tarbert 2 Tarbert2-Tarbert1 Top Ness-Ness1
Fluid Contacts GOC 1697.96 mWOC 1910.0 m
Pressure @ bubble point 2516.7 psia
Temperature 220degFBo 1.1 bbl/stb
Solution GOR 1.1342 scf/stbOil Viscosity 1.33cpOil Density 45.11lb/ft3Gravity API 64.129
STOIIP(*10^6m3) 397.0GIIP(*10^8m3) 103.54 64.23 229.85
Porosity Range 0.9 to 1.0
Swc
Good Sand : 0.22-0.28Fair Sand : 0.35- 0.38Shaly Sand : 0.25-0.30
Initial Pressure 2516psia
Table 1. Reservoir Characteristics of 3 potential production zones
Reservoir Characteristic
Reservoir Fluid Studies• Important input for reservoir numerical modeling is provided by PVT analysis of
reservoir fluid samples• A set of Gullfaks field oil and gas separator samples were collected on 1st July 2011
Type of sample Separator Oil Separator GasCylinder no. 1339-GFK 2339-GFKOpening pressure at separator temperature, oF, psig
[email protected] [email protected]
Approximate sample volume @ 1000 psig
575 20000 @ 125 psig
Bubble point pressure at separator temperature, oF, psig
Remarks Pair with 2339-GFK Pair with 1339-GFK
Table 2. Quality Check of Separator
Reservoir Fluid Studies
• There are several laboratory tests that are routinely conducted to characterize the reservoir fluids
• To obtain the value of Saturation Pressure, Pb
• To obtain the total Hydrocarbon volume as a function of pressure
Constant Composition Expansion Test (CCE)
• To obtain amount of gas in solution• The shrinkage in the oil volume as a
function of pressure• Gas Compressibility factor, gas specific
gravity and density of the remaining oil
Differential Liberation Test (DLE)
• The separator test was conducted as two separate single stage separator test at specified separator conditions.
Separator Test
Swelling Tests for CO2 and N2
• This test is to check the oil vaporisation from the formation
Quality Check
Figure 1. Phase plot for Gullfaks
• Clearly shown that the oil is black oil type as the reservoir temperature is far to the left from the critical temperature.
• This analysis is also supported by the laboratory experiments where mole fraction of heptanes plus (C7+) is more than 30% (more heavy hydrocarbon).
Reservoir Fluid Studies(using PVTi Software)
Figure 2. Relative Volume Figure 3. Liquid Density
Figure 4. Oil Relative Volume Figure 5. Gas Gravity
Figure 6. Gas-oil Ratio Figure 7. Gas Formation Volume Factor
Figure 8. Vapor Z-factor
• Three samples were reported in the Special Core Analysis (SCAL) report.• Samples are taken at depth intervals of 1794-1796m, 1824-1827m and 1903-
1905m. The measured capillary pressures are classified according to the sand facies.
• J-function – To transform the capillary pressure curve to a universal curve before classifying according sand facies.
• Capillary Pressure – To derive J-function to develop initial water saturation distribution in the reservoir.
• Poor reservoir rock will show higher connate water saturation and higher transition zone due to smaller capillary tube.
Special Core Analysis (SCAL)
Core Sample Depth Permeability Porosity Capillary Pressure
Group
1-2001 1750 385 0.28 Good Sand
1-3001 1795 58 0.175 Shaly Sand
1-4003 1904 212 0.22 Fair Sand
Table 4. Capillary Pressure classification according to
sand facies
Table 3. Laboratory-reservoir fluid properties for capillary conversion
Figure 9. Capillary Pressure curve classification based on J-function vs. Sw
normalised
• The data will be grouped according to the shape of the curve plotted thus rocks can be assigned with its own relative permeability curve.
• After careful inspection, the relative permeability data can be grouped according to the rock quality.
• The normalized relative permeability curves for both gas-oil and oil-water systems of each facies were matched by the best fit Corey exponents.
Figure 10. Normalized relative permeability curves for gas-oil
Figure 11. Normalized relative permeability curves for oil-water
Facies: Good sand Nw = 4.4 Now = 3 Ng = 6
Figure 12. Corey fitted curves and de-normalized curves for good sand
Figure 13. Corey fitted curves and de-normalized curves for shaly sand
Figure 14. Corey fitted curves and de-normalized curves for fair sand
Reservoir Simulation Study
&
RESERVOIR SIMULATION STUDY
• It is crucial to determine which stage the reservoir is currently going through.
• It determines the main objectives of the reservoir simulation operations.
• It can be determined by the amount of hydrocarbon reserves inside the field and the total number of wells drilled.
Field Preliminary Study FIELD PRELIMINARY STUDY
Stage Percentage of Wells Drilled
Exploration <10%
Appraisal <25%
Development <50%
Production >50%
Field Preliminary Study
Number of Wells Already Drilled is: 12 WellsSTOIIP: 397 million metric cubesWhat’s the optimum number of wells Needed??
Adopted from Atlantic petroleum company website
FIELD PRELIMINARY STUDY
• Corrie and Inemaka (2001) presented an analytical equation to estimate the optimum number of wells required to fully develop an oilfield.
Optimum number of wells required
NPV vs. Number of Wells Plot
OPTIMUM NUMBER OFWELL
• The number of wells required will be approximately 190 wells.
• Gullfaks has 12 Already Drilled Wells which is less than 10% of the optimum number of wells required.
• According to SLB online field Glossary:“Appraisal of a discovery involves drilling further wells to reduce the degree of uncertainty in the size and quality of the potential field.”
Optimum number of wells required OPTIMUM NUMBER OF
WELL
Reservoir Simulation Objectives
• Since the Field is currently undergoing the early stages of the appraisal phase, the Reservoir simulation objectives are:1. To propose drilling more wells and specify well
locations to reduce the degree of uncertainty in the size and quality of the potential field.
2. To develop a justifiable numerical simulation model to predict reservoir performance.
3. To propose a suitable depletion strategy and water injection strategy.
4. To conduct a preliminary EOR screening plan.
SIMULATION OBJECTIVES
Well Engineering
• After the optimum number of wells is acquired, the well engineering process is mainly divided into 2 main phases;1. Well target locations.2. Well completion
• A portion only of the required wells should be drilled.
• The performance and the geology encountered through the new drilled wells should be evaluated.
WELL ENGINEERING
Well Target locations
• In ensuring the best strategic location is selected, few main reservoir criteria are fulfilled;1. Area with high oil saturation 2. Good rock quality in terms of permeability and
porosity 3. Away from fault 4. Representative of average reservoir properties 5. Reservoir thickness 6. Well Clearance
WELL TARGET LOCATION
Well Target locations
Oil saturation map Rock Quality Index mapOil saturation X RQI map
=X
WELL TARGET LOCATION
Well Target locations• 20 new wells are proposed at different reservoir
locations.• The Kick off point was assumed to be -800.00 meters.• The maximum inclination was determined to be less
than 30 degrees.• Three Drilling Platforms:
– Platform A– Platform B– Platform C
Existing & proposed wells
WELL TARGET LOCATION
Well Completion
• All the newly drilled Wells were completed in the same manner.1. Production Casing2. Production Tubing3. Perforations4. Pressure Gauge
WELL COMPLETIONS
Well Optimum Production Rate
• Various simulation runs were conducted in order to determine the optimum well production rate.
Input Value
Number of Wells 32 (12 old +20 New)
Depletion Method Natural depletion
Production Control mode Control by oil Rate
Field Water Cut limit 0.5
Field Gas oil ratio limit 100 Sm3/SM3
Action if limits are violated Shut Worst Well
WELL OPTIMUM PRODUCTIONRATE
Well Optimum Production Rate
Recovery Factor Vs. Well Production Rate
• Based on the Sensitivity analysis the optimum production rate is 150 SM3/day for each well
WELL OPTIMUM PRODUCTIONRATE
Base Case Simulation Model• Base case model is run by eclipse in order to predict field
performance• This model is utilized as the main reference for the use of
comparing with other simulation• Input Data Input Value
Number of wells 32
Type of well Deviated
Depletion method Natural depletion
Production control mode Control by oil rate
Oil Rate 150 SM3/Day
Water Cut Limit for the field 0.5
Gas Oil ratio limit 100 SM3/SM3
Run Duration 20 years
BASE CASE SIMULATIONMODEL
Base Case Model Result BASE CASE SIMULATION
RESULT
Base Case Simulation ResultBase Case Model ResultCumulative Oil Production
32.78 million m3
Recovery Percentage 8.25%Drive mechanism Water aquifer and
Gas CapPressure depletion 2.00 Bar/ Year
BASE CASE SIMULATION RESULT
Development Strategy
• Based on the result obtained from the base case model-Gullfaks reservoir has dominant in water aquifer and gas cap as drive mechanism
• Able to support the reservoir pressure at a constant pseudo steady state decline rate
• Utilized water injection in order to support reservoir pressure and prevent further expansion of gas cap as the pressure drop below the bubble point
• Reservoir with big gas cap and water aquifer will result in 20-40% oil recovery
• Improved from primary recovery of 20 years production for 32 wells with only 8.25% oil recovery
DEVELOPMENT STRATEGY
• Sensitivity analysis shows to what extent the viability of a project is influenced by variations in major quantifiable
• Technique to investigate the impact of changes in project variables on the base case
• Purpose of doing sensitivity analysis is to help to identify the key variables which influence the project effectiveness
• Reservoir performance can be optimized by doing sensitivity analyses based on the simulation base case result
• Sensitivity analyses are also performed to rank the importance of reservoir parameters which affects production performance which are :
1. Number of injection wells2. Injection rate3. Injection start time
SENSITIVITY ANALYSIS FORWATER INJECTION STRATEGY
1. Number of injection well– Injection Well = C2,C3,C4,C5 and C6
Variable Case 1 Case 2 Case 3 Case 4 Case 5
Number of Injection well 1 2 3 4 5
Start of injection After 20 years of Primary Production
Injection Rate Same as production control mode rate ( 150 SM3 )
Duration of injection Strategy 25 years
Additional Oil Recovery 10.10% 10.23% 10.31% 10.25% 10.18%
Optimum Recovery
SENSITIVITY ANALYSIS FORWATER INJECTION STRATEGY
2. Injection rate
Variable Case 1 Case 2 Case 3 Case 4 Case 5
Number of Injection well 3 injectors
Start of injection After 20 years of Primary Production
Injection Rate (SM3/ Day ) 150 200 250 300 350
Duration of injection strategy 25 Years
Additional Oil Recovery 10.31% 10.41% 10.62% 10.65% 10.63%
Optimum Recovery
SENSITIVITY ANALYSIS FORWATER INJECTION STRATEGY
3. Injection start time
Variable Case 1 Case 2 Case 3 Case 4 Case 5
Number of Injection well 3 injectors
Start of injection after primary production ( Year)
0 5 10 15 20
Injection Rate ( SM3/ Day ) 300
Duration of Injection strategy 25 Years
Additional Oil Recovery 10.49% 10.52% 10.74% 10.68% 10.65%
Optimum Recovery
SENSITIVITY ANALYSIS FORWATER INJECTION STRATEGY
• Summary of analysisVariable Optimum Water injection case
Number of injection Wells 3 injectors
Start of Injection after primary production 10 years
Injection Rate 300 SM3/ Day
Duration of Injection strategy 25 Years
Additional Oil recovery 10.74%
Total recovery ( Primary + secondary recovery ) 14.86%
SENSITIVITY ANALYSIS FORWATER INJECTION STRATEGY
• Water flooding data inputInput value
Number of wells 32
Type of wells Deviated
Strategy method Water flooding
Injection Rate 300 SM3/Day
Injection Well C3, C4 and C6
Oil rate 30 SM3/ Day
Water Cut Limit for the field 0.5
Gas oil ratio limit 100 SM3/SM3
Action if limits are violated Shut worst well
PROPOSED WATER INJECTIONSTRATEGY SIMULATION RESULTS
PROPOSED WATER INJECTIONSTRATEGY SIMULATION RESULTS
PROPOSED WATER INJECTIONSTRATEGY SIMULATION RESULTS
Water Injection Strategy
Result
Cumulative Oil Production
56 million m3
Recovery Percentage
10.74%
Drive mechanism
Water injection ( Secondary Recovery)
Pressure depletion
Maintain at 148-150 Bar/ Year of injection
Base Case Model Result
Cumulative Oil Production
32.78 million m3
Recovery Percentage 8.25%
Drive mechanism Water aquifer and Gas Cap
Pressure depletion 2.00 Bar/ Year
Comparison of simulation result between water injection and base case
PROPOSED WATER INJECTIONSTRATEGY SIMULATION RESULTS
RECOMMENDED PRIMARY + SECONDARY
TOTAL RECOVERY 14.86 %
EOR Preliminary Consideration
• Feasible for early consideration in order to anticipate unrecoverable oil during natural depletion phase
• Improved recovery from 30 to 60% of oil recovery• Require a large amount of investment and operating
expenses• Technical uncertainties and risks are needed to be
appropriately identified to support investment decision• Gullfaks was screened for potential EOR application• Crude oil quality, reservoir temperature and pressure are
among the EOR process of screening criteria
EOR PRELIMINARY CONSIDERATION
EOR Preliminary Consideration
• Reservoir Fluid Properties for Gullfaks Property Value
Oil Gravity o(API) 30
Reservoir Temperature, o F 220
Original Reservoir Pressure, psia 2516
Oil viscosity, cp 1.33
Solution Gas GOR, SCF/ STB 1.1342
Porosity, fraction 0.28
Horizontal Permeability, md 220 mD
Reservoir Depth, ft 2400
Residual Oil Saturation 0.7535
EOR PRELIMINARY CONSIDERATION
EOR Preliminary Consideration
Categorization of EOR techniques:1. Gas injection2. Chemical injection- Polymer injection3. Water alternating gas injection4. Thermal recovery
Recommended techniqueWater Alternating Gas injection ( WAG)
EOR PRELIMINARY CONSIDERATION
EOR Preliminary Consideration
Advantages of WAG1. Overcome disadvantages of water flooding and gas
injection as single EOR- Poor macroscopic sweep efficiency due to fingering effects
2. Improve mobility ratio3. Reduce the instability of the gas-oil displacement4. WAG can control fluid profile5. Relatively cheap by minimizing the volume of gas to be
injected through WAG
EOR PRELIMINARY CONSIDERATION
CHAPTER 5: Conclusion
• Conclusion• Recommendation• References
CONCLUSION• Gulfaks field difficult to develop due to its complexity of geologic condition.• Static modelling was built in geophysics and geology phase, in order to provide static description of the reservoir.• Outcome from this phase-
STOIIP= 397x106 m3
GIIP= 80662x106sm3
• In Petrophysic phase, the volume of hydrocarbons present in a reservoir can be determine.• Outcome of this phase-
A15 and B9 produce more hydrocarbon C3 will be an injection well due to little hydrocarbon at this area
• Reservoir simulation model was created to models are used in developed fields where production forecasts are needed to help make investment decision
• Outcome of this phase- Number of well is 190 wells Well target location is 20 new well Optimum production rate is 150sm3/day Cumulative Oil production is 32.78m3
• Gullfaks reservoir has dominant in water aquifer and gas cap as drive mechanism• Water injection was used to simulate the production.• From sensitivity analyses, the result are -
Number of injection wells (3,10.3`%) Injection rate (300SM3,10.65%) Injection start time (10 year, 10.78%)
• Field development plan pending until reservoir phase due to time constraint.
Conclusion
RECOMMENDAION
• Future plan proceed with other phase Production technologitsDrilling and CompletionFacilities EngineeringEconomic AnalysisHSE
Recommendation
RECOMMENDAION1. Ahmad, T. (2000). Reservoir Engineering Handbook. Houston, Texas: Gulf Publishing Company. 2. Brock, J. Applied Open Hole Log Analysis - A step by step course in well log interpretation - from
fundamentals to advanced concepts (Vol. 2). Contribution in Petroleum Geology and Engineering. 3. Cacoana, A. (1992). Hydrocarbon Classification and Oil Reserves - Applied Enhanced Oil Recovery.
Englewood Cliffs, New Jersey: Prentice-Hall. 4. Jr, S. B. (2006). Principles of Sedimentalogy and Stratigraphy. Pearson and Prentice Hall. 5. Norton, J. (2002). Formulas and Calculations for Drilling, Production and Workover (Second ed.).
Houston, Texas: Gulf Publishing Company. 6. Salley, R. C. (1986). Element of Petroleum Geology. Academic Press. 7. SCHLUMBERGER. (2008). PIPESIM Fundamentals. SCHLUMBERGER. 8. Tiab, D., & Donaldson, E. C. (2004). Petrophysics: Theory and Practice of Measuring Reservoir Rock
and Fluid Transport Properties. Gulf Professional Publishing. 9. William, C. (1996). Standard Handbook of Petroleum and Natural Gas Engineering (Second ed.).
Houston, Texas: Gulf Publishing Company. 10. Differental Liberation (Vaporization) Test. (n.d.). Retrieved from
http://www.assignmenthelp.net/assignment_help/differental-liberation-test.php 11. PVT experiments – Constant Composition Expansion ( CCE ). (n.d.). Retrieved from
http://www.engineering-techniques.com/reservoir-engineering/pvtexperiments-% E2%80%93-cce
References
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