Field Development Plan Final Presentation Field Development Plan Group 6 Abdul Afif Osman 12501 Elisha Md Talip 12564 Harun Abd Rahman 12979 Mohamed Yousry Ahmed Hussien 12279 Mohd Ridzuan Hamid 12688 Muhammad Afdhaludden Azmi 12712 Muhammad Haidir Nizam Baharuddin 12736 Norsyuhada Abd Razak 12796

PRESENTATION OUTLINE INTRODUCTION GEOLOGY & GEOPHYSICS PETROPHYSICS RESERVOIR CONCLUSION & RECOMMENDATION

CHAPTER 1: INTRODUCTION Backgroud of Study Problem Statement Objectives Gantt Chart

BACKGROUND OF STUDY 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. 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 16 FDP 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 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 Regional position of the Northern North Sea and the study area

Geological setting 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.

Reservoir Geology 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 GEOLOGY Three 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. The change in relative sea level occurred as a transition to transgressive cycle in Ness time dividing this unit into Lower and Upper Ness.

Volumetric Calculation Uncertainty & Optimization 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

Structural Modelling STATIC MODELLING 1) Making surface Base Cretaceous 2) Defining exaggeration Top Tarbert Top Ness Top Etive Base Cretaceous 1) Making surface

Structural Modeling STATIC MODELLING 4) Zonation & layering 3) Defining well tops 4) Zonation & layering

Structural model of Gullfaks STATIC MODELLING Structural Modelling Structural model of Gullfaks

Skeletal structure model of Gullfaks STATIC MODELLING Structural Modelling Skeletal structure model of Gullfaks

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 »»

Fluid Contacts using MDT Formation Pressure Plot Gas-Oil Contact (GOC) Using data of well A10 1697.95 m (5570.70 ft) 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

Fluid Contacts using MDT Formation Pressure Plot Oil-Water Contact (OWC) Using data of well B9 1905.05 m (6250.15 ft) 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

Fluid Contacts using Resistivity Log Fluid 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 Contact model from Above Fluid Contacts 3D Model FLUID CONTACT 3D MODEL Fluid Contact model from Above

Cross-section of Fluid Contacts model Cross-sectional model of Fluid Contacts (east-west)

Figure 1: Base Cretaceous surface map with cross section line RESERVOIR MAPPING Reservoir Mapping 2 Dimensional Imaging A B C D Vertical Cross Section Horizontal Cross Section Figure 1: Base Cretaceous surface map with cross section line

RESERVOIR MAPPING Horizontal Cross Section B8, B9, C5 and C6 GOC 1697m WOC 1905m Zone 1 Zone 2 Zone 3 Zone 4 Zone 5 Base Cretaceous Top Talbert Top Ness Top etive Horizontal Cross Section B8, B9, C5 and C6

RESERVOIR MAPPING Vertical Cross Section A15, B9 and C3 GOC 1697m WOC Zone 1 Zone 2 Base Cretaceous Top Talbert Top Ness Top etive Vertical Cross Section A15, B9 and C3

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 3E SAS 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: Gamma Ray Log Porosity Log 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) Reservoir Engineering (Intro) 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 Characteristics 6 Zones:   Top Tarbert- Tarbert 2 Tarbert2- Tarbert1 Top Ness-Ness1 Fluid Contacts GOC 1697.96 m WOC 1910.0 m Pressure @ bubble point 2516.7 psia Temperature 220degF Bo 1.1 bbl/stb Solution GOR 1.1342 scf/stb Oil Viscosity 1.33cp Oil Density 45.11lb/ft3 Gravity API 64.129 STOIIP(*10^6m3) 397.0 GIIP(*10^8m3) 103.54 64.23 229.85 Porosity Range 0.9 to 1.0 Swc Good Sand : 0.22-0.28 Fair Sand : 0.35- 0.38 Shaly Sand : 0.25-0.30 Initial Pressure 2516psia Base Cretaceous – Top Tarbert Top Tarbert – Tarbert 1 Zones which have possible amount of oil to be recovered Tarbert 1 – Tarbert 2 Tarbert 2 – Top Ness Top Ness – Ness 1 Ness 1 – Top Etive Table 1. Reservoir Characteristics of 3 potential production zones

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 Gas Cylinder no. 1339-GFK 2339-GFK Opening pressure at separator temperature, oF, psig 100@95.0 125@95.0 Approximate sample volume @ 1000 psig 575 20000 @ 125 psig Bubble point pressure at separator temperature, oF, psig NA Remarks Pair with 2339-GFK Pair with 1339-GFK Table 2. Quality Check of Separator

Quality Check 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

Reservoir Fluid Studies (using PVTi Software) 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).

Figure 2. Relative Volume Figure 3. Liquid Density Figure 4. Oil Relative Volume Figure 5. Gas Gravity

Figure 7. Gas Formation Volume Factor Figure 6. Gas-oil Ratio Figure 7. Gas Formation Volume Factor Figure 8. Vapor Z-factor

Special Core Analysis (SCAL) 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.

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 Table 4. Capillary Pressure classification according to sand facies

Figure 10. Normalized relative permeability curves for gas-oil Figure 11. Normalized relative permeability curves for oil-water 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 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 &

Field Preliminary 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 Stage Percentage of Wells Drilled Exploration <10% Appraisal <25% Development <50% Production >50% Adopted from Atlantic petroleum company website Number of Wells Already Drilled is: 12 Wells STOIIP: 397 million metric cubes What’s the optimum number of wells Needed??

Optimum number of wells required Corrie and Inemaka (2001) presented an analytical equation to estimate the optimum number of wells required to fully develop an oilfield. NPV vs. Number of Wells Plot

Optimum number of wells required 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.”

Reservoir Simulation Objectives Since the Field is currently undergoing the early stages of the appraisal phase, the Reservoir simulation objectives are: To propose drilling more wells and specify well locations to reduce the degree of uncertainty in the size and quality of the potential field. To develop a justifiable numerical simulation model to predict reservoir performance. To propose a suitable depletion strategy and water injection strategy. To conduct a preliminary EOR screening plan.

Well Engineering WELL ENGINEERING After the optimum number of wells is acquired, the well engineering process is mainly divided into 2 main phases; Well target locations. 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 Target locations WELL TARGET LOCATION In ensuring the best strategic location is selected, few main reservoir criteria are fulfilled; Area with high oil saturation Good rock quality in terms of permeability and porosity Away from fault Representative of average reservoir properties Reservoir thickness Well Clearance

Well Target locations X = WELL TARGET LOCATION Oil saturation map Rock Quality Index map Oil saturation X RQI map

Well Target locations WELL TARGET LOCATION 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 WELL COMPLETIONS All the newly drilled Wells were completed in the same manner. Production Casing Production Tubing Perforations Pressure Gauge

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 Production Rate Based on the Sensitivity analysis the optimum production rate is 150 SM3/day for each well Recovery Factor Vs. Well Production Rate

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 SIMULATION RESULT Base Case Model Result

Base Case Simulation Result 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

Development Strategy 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

SENSITIVITY ANALYSIS FOR WATER INJECTION 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 : Number of injection wells Injection rate Injection start time

SENSITIVITY ANALYSIS FOR WATER 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 FOR WATER 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 FOR WATER 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) 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 FOR WATER INJECTION STRATEGY Summary of analysis Variable 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%

PROPOSED WATER INJECTION STRATEGY SIMULATION RESULTS Water flooding data input Input 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 INJECTION STRATEGY SIMULATION RESULTS

PROPOSED WATER INJECTION STRATEGY SIMULATION RESULTS

PROPOSED WATER INJECTION STRATEGY SIMULATION RESULTS Comparison of simulation result between water injection and base case 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 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

EOR Preliminary Consideration Categorization of EOR techniques: Gas injection Chemical injection- Polymer injection Water alternating gas injection Thermal recovery Recommended technique Water Alternating Gas injection ( WAG)

EOR Preliminary Consideration Advantages of WAG Overcome disadvantages of water flooding and gas injection as single EOR- Poor macroscopic sweep efficiency due to fingering effects Improve mobility ratio Reduce the instability of the gas-oil displacement WAG can control fluid profile Relatively cheap by minimizing the volume of gas to be injected through WAG

CHAPTER 5: Conclusion Conclusion Recommendation References

CONCLUSION 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 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.

RECOMMENDAION Recommendation Future plan proceed with other phase Production technologits Drilling and Completion Facilities Engineering Economic Analysis HSE

RECOMMENDAION References Ahmad, T. (2000). Reservoir Engineering Handbook. Houston, Texas: Gulf Publishing Company. 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. Cacoana, A. (1992). Hydrocarbon Classification and Oil Reserves - Applied Enhanced Oil Recovery. Englewood Cliffs, New Jersey: Prentice-Hall. Jr, S. B. (2006). Principles of Sedimentalogy and Stratigraphy. Pearson and Prentice Hall. Norton, J. (2002). Formulas and Calculations for Drilling, Production and Workover (Second ed.). Houston, Texas: Gulf Publishing Company. Salley, R. C. (1986). Element of Petroleum Geology. Academic Press. SCHLUMBERGER. (2008). PIPESIM Fundamentals. SCHLUMBERGER. Tiab, D., & Donaldson, E. C. (2004). Petrophysics: Theory and Practice of Measuring Reservoir Rock and Fluid Transport Properties. Gulf Professional Publishing. William, C. (1996). Standard Handbook of Petroleum and Natural Gas Engineering (Second ed.). Houston, Texas: Gulf Publishing Company. Differental Liberation (Vaporization) Test. (n.d.). Retrieved from http://www.assignmenthelp.net/assignment_help/differental-liberation-test.php PVT experiments – Constant Composition Expansion ( CCE ). (n.d.). Retrieved from http://www.engineering-techniques.com/reservoir-engineering/pvtexperiments-% E2%80%93-cce

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