1. Field Development Plan
Final Presentation
Field Development Plan
Group 6
Abdul Afif Osman
Elisha Md Talip
Harun Abd Rahman
Mohamed Yousry Ahmed Hussien
Mohd Ridzuan Hamid
Muhammad Afdhaludden Azmi
Muhammad Haidir Nizam Baharuddin 12736
Norsyuhada Abd Razak

2. PRESENTATION OUTLINE INTRODUCTION GEOLOGY & GEOPHYSICS PETROPHYSICS
RESERVOIR
CONCLUSION
&
RECOMMENDATION

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

4. 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

5. 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

6. 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.

7. 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.

8. 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

9. CHAPTER 2: GEOLOGY & GEOPHYSICS
Geological setting
Reservoir geology
Static modeling
Fluid contacts
Reservoir Mapping
Volumetric Calculation

10. 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 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

11. 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.

12. 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.

13. 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

14. 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.

15. 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

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

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

18. Structural model of Gullfaks
STATIC MODELLING
Structural Modelling
Structural model of Gullfaks

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

20. 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 »»

21. 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 »»

22. Fluid Contacts using MDT Formation Pressure Plot
Gas-Oil Contact (GOC)
Using data of well A10
m ( ft)
TVD (ft)
Formation Pressure (psia)

23. Fluid Contacts using MDT Formation Pressure Plot
Oil-Water Contact (OWC)
Using data of well B9
m ( ft)
TVD (ft)
Formation Pressure (psia)

24. 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 = m

25. Fluid Contact model from Above
Fluid Contacts 3D Model
FLUID CONTACT 3D MODEL
Fluid Contact model from Above

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

27. 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

28. 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

29. 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

30. 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

31. VOLUMETRIC CALCULATION
From Petrel
From Statoil Report ( )
From report by Terra 3E
SAS
STOIIP [mill sM3]
397
396.93
383
GIIP [bill sM3]
80.6
80.1 -

32. CHAPTER 3: PETROPHYSICS
Log Correlation

33. 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

34. 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 – 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.

35. CHAPTER 4: RESERVOIR
Reservoir Engineering
Reservoir Characteristic
Fluid Studies
SCAL
Reservoir simulation study

36. 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

37. Reservoir Characteristics
6 Zones:
Top Tarbert- Tarbert 2
Tarbert2- Tarbert1
Top Ness-Ness1
Fluid Contacts
GOC m
WOC m
bubble point
psia
Temperature
220degF Bo
1.1 bbl/stb
Solution GOR
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 :
Fair Sand :
Shaly Sand :
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

38. 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
Approximate sample 1000 psig
575
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

39. 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

40. 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).

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

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

43. Special Core Analysis (SCAL)
Three samples were reported in the Special Core Analysis (SCAL) report.
Samples are taken at depth intervals of m, m and m. 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.

44. 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

45. 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.

46. Figure 12. Corey fitted curves and de-normalized curves for good sand

47. Figure 13. Corey fitted curves and de-normalized curves for shaly sand

48. Figure 14. Corey fitted curves and de-normalized curves for fair sand

49. Reservoir Simulation Study
&

50. 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.

51. 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??

52. 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

53. 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.”

54. 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.

55. 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.

56. 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

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

58. Well Target locations WELL TARGET LOCATION
20 new wells are proposed at different reservoir locations.
The Kick off point was assumed to be meters.
The maximum inclination was determined to be less than 30 degrees.
Three Drilling Platforms:
Platform A
Platform B
Platform C
Existing & proposed wells

59. Well Completion WELL COMPLETIONS
All the newly drilled Wells were completed in the same manner.
Production Casing
Production Tubing
Perforations
Pressure Gauge

60. 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

61. 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

62. 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

63. BASE CASE SIMULATION
RESULT
Base Case Model Result

64. 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

65. 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

66. 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

67. 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

68. 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

69. 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

70. 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%

71. 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

72. PROPOSED WATER INJECTION STRATEGY SIMULATION RESULTS

73. PROPOSED WATER INJECTION STRATEGY SIMULATION RESULTS

74. 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 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 %

75. 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

76. 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

77. 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)

78. 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

79. CHAPTER 5: Conclusion
Conclusion
Recommendation
References

80. 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.

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

82. 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
PVT experiments – Constant Composition Expansion ( CCE ). (n.d.). Retrieved from E2%80%93-cce

83. Question
&
Answer