Group 6 Abdul Afif Osman12501 Elisha Md Talip12564 Harun Abd Rahman12979 Mohamed Yousry Ahmed Hussien 12279 Mohd Ridzuan Hamid 12688 Muhammad Afdhaludden

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


1) Making surface

STATIC MODELLING

Base Cretaceous

Structural Modeling STATIC MODELLING

3) Defining well tops

4) Zonation & layering


Structural model of Gullfaks

STATIC 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

[email protected] NA

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 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 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


2. Injection rate


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


Optimum Recovery


3. Injection start time


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


Optimum Recovery


• 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%


• 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



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


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


• 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



Categorization of EOR techniques:1. Gas injection2. Chemical injection- Polymer injection3. Water alternating gas injection4. Thermal recovery

Recommended techniqueWater Alternating Gas injection ( WAG)



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


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

Question&

Answer

Documents

Group 6 Abdul Afif Osman12501 Elisha Md Talip12564 Harun Abd Rahman12979 Mohamed Yousry Ahmed Hussien 12279 Mohd Ridzuan Hamid 12688 Muhammad Afdhaludden