1. FIELD DEVELOPMENT PROJECT (GULLFAKS FIELD)
GROUP 13
Nur Syazwani Moktar
Kong Fook Ann
Teoh Kheng Keat
Muhammad Syamim Hussain
Mohamed Saifullah Sirajudin
Arunan Isvaran
Adnane Mohamed Abdellahi Zeine
Malik Muhammad Humza

2. PRESENTATION OUTLINE Introduction Geology & Geophysics Petrophysics
Reservoir Engineering
Conclusions

3. Location of Gullfaks field in the North Sea
Introduction
Located in the north-eastern part of block 34/10 in the Norwegian sector of the North Sea along the western flank of the Viking Graben.
Subdivided into 4 major stratigraphic units as studied in this project which are the Cretaceous, Tarbert, Ness and Etive formations.
This petroleum system is a sequence of sandstones, siltstones, shales and coals with maximum thickness of m.
Location of Gullfaks field in the North Sea

4. Problem Statement
Development of structurally complex oil and gas field requires a thorough understanding of the geological characteristics and reservoir characteristics in order to optimize the field performance.
This case study focuses on the necessary aspects in field development process from Geology and Geophysics up to Reservoir Engineering.

5. Objectives
The objectives in developing the best, possible FDP will include the following:
Maximizing economic return
Maximizing recoverable hydrocarbons
Maximizing hydrocarbon production
Compliance with health, safety and environment requirements
Providing recommendations in reducing risks and uncertainties
Providing sustainable development options

6. Geology & Geophysics Petroleum System 2D Cross Section Imaging
Stratigraphic Correlation
Depositional Environment
Volumetric Estimation

7. Petroleum System Source Rock Draupne Formation
Main Shale rock that forms the hydrocarbon source in this field
Physical Characteristics Include
Brownish Black
Medium of Dark Olive Grey
Non- Calcareous Mudstones
Thickness of Formation typically m but may exceed 1200m in localized area
Heather Formation
Dark grey Silty Mudstones with thin Carbonate layers
Thickness formation ranges up to 1000 m
It is typically gas prone
Total organic carbon ( TOC ) values are typically between %

8. Petroleum System Reservoir Rock Triassic and Lower Jurassic
Occurs in tilted fault blocks with varying degree of Jurassic
Cretaceous erosion and onlap.
The main reservoir intervals comprise of thick , fluvial channel and sheetflood deposit.
Porosity range from 20-24%
Permeability mD
Middle Jurassic
Present in the Northen Sea are arkoses and subarkoses with quartz , clay minerals and Fledspars consisting about 95 % of the total miner
Sandstones are both quartz and calcite cemented at depths exceeding 2500 m.
Reservoir form a thick clastic wedge comprising laterally extensive interconnected fluvial
Deltaic and coastal depositional systems with porosities 20-30% and permeability 50 – 500 mD.

9. Petroleum System Traps and Seals Traps
Most trapping mechanism is provided by rotated faults sealed by fine grained post rift sediments.
Seals
These sediments draped on to the structures to form seals
Lateral trapping and sealing is formed where reservoir rocks are juxtaposed with non-reservoir rocks at fault contacts
Most seals are closed to hydraulic fracture.

10. Petroleum System Migration Migration Mechanism
Primary migration - Pressure driven flow of a discrete hydrocarbon phase through pores and micro fractures
Secondary migration - Buoyancy resulting from difference in density between the hydrocarbon and water

11. 2D Cross Section Imaging

12. Stratigraphic Correlation
Unconformity
Thinning Strata S-N
Thickening Strata S-N

13. Depositional Environment

14. 3D Static Modeling Isochore Points on Static Model
Static Model Thickness Defined (Lateral View)

15. Volumetric Estimation

16. Breakdown of STOIIP Based on Layers

17. Breakdown of GIIP Based on Layers

18. Petrophysics Lithology Fluid Types & Fluid Contacts Pressure Plot
Volume of Shale
Porosity

19. Lithology Zone Interpretation Log Section Top Tarbert - Tarbert 2
Depth:
m to m
The lithology shows high percentage of sandstone (70%) and the rest is made up by silt.
Sand – 70%
Silt – 30%
Tarbert 2 – Tarbert 1
m to m
In this zone, sandstone interbedded with silts.
Sand – 61%
Silt – 39%
Tarbert 1 – Top Ness
m to m
Shale in this particular zone has almost the same percentage as silt.
Shale – 53%
Silt – 47%
Top Ness – Ness 1
m to m
This zone is mainly sandstone with 93%.
Sand – 93%
Silt – 7%
Ness 1 – Top Etive
m to m
In this zone, shale shows a very high percentage.
Shale – 99%
Sand – 1%

20. Fluid Types & Fluid Contacts
Oil
POWC
Water

21. Water gradient=0.44 psi/ft
Pressure Plot
Gas gradient=0.01 psi/ft
Oil gradient=0.25 psi/ft
GOC = 1701 m TVDSS
OWC = 1902 m TVDSS
Water gradient=0.44 psi/ft

22. Volume of Shale (Vsh) Zone GR log (average) Volume of shale (%)
Interpretation
Top Tarbert - Tarbert 2
53.7
24.4
Tarbert 2 - Tarbert 1
68.5
38.3
Tarbert 1 - Top Ness
98.1
66.0
Top Ness - Ness 1
53.4
24.1
Ness 1 - Top Etive
127.1
93.2

23. Volume of Shale (Vsh) Porosity (Ø)
Zone
Average Shale Volume (%)
Top Tarbert – Tarbert 2
10.1
Tarbert 2 – Tarbert 1
34.6
Tarbert 1 – Top Ness
60.2
Top Ness – Ness 1
27.3
Ness 1 – Top Etive
90.4
Porosity (Ø)
Zone
Average Effective Porosity
Top Tarbert – Tarbert 2
0.184
Tarbert 2 – Tarbert 1
0.187
Tarbert 1 – Top Ness
0.160
Top Ness – Ness 1
0.178
Ness 1 – Top Etive
0.108

24. Reservoir Engineering
Reservoir Fluid Studies
SCAL

25. Reservoir Fluid & SCAL Reports
Reservoir Fluid Report:
Constant Composition Expansion Test (CCE)
Differential Liberation Test (DLE)
Separator Test
Swelling Tests for CO2 and N2
SCAL Report:
Capillary Pressure Test (Oil-Water)
Relative Permeability Test (Gas-Oil, Oil-Water)

26. Summary of PVT Results
The following is the summary of the results obtained from the PVT analysis.
Reported Reservoir Conditions
Reservoir Pressure : 2516 psia
Reservoir Temperature : 220 oF
Constant Composition Expansion
Bubble-point Pressure : psia
Differential Liberation Test
Oil Formation Volume Factor : 1.1 bbl/STB
Solution Gas-Oil Ratio : Mscf/STB
Oil Density : lb/ft3
Reservoir Fluid Viscosity
Oil Viscosity : 1.33 cp

27. Phase Plot
Phase Plot for Gullfaks DST #1

28. Reservoir Fluid Properties
Relative Volume
Liquid Density
Oil Relative Volume
Gas Gravity

29. Reservoir Fluid Properties
Gas Oil Ratio
Gas FVF
Vapor z Factor

30. Capillary Pressure & J-Function
Good sand
Shaly sand
Fair sand
Capillary pressure curve classification based on J-function vs. Sw normalized

31. Relative Permeability
Normalized relative permeability curves for oil-water
Normalized relative permeability curves for gas-oil

32. Reservoir Engineering
Reservoir Simulation Studies

33. Reservoir Drive Mechanisms and Energy Plot
Has Gas-Oil Contact and Water-Oil Contact (might have gas cap drive+water drive).
Initial reservoir pressure psia and bubble point pressure of psia (might have solution gas drive).
MBAL cannot be done due to insufficient data.
Assume that the reservoir is producing through its natural depletion (fluid expansion).

34. 3D Geological Static Model Export
3D static model was developed using PETREL 2012

35. Sensitivity Analysis Base Case Analysis Water Injector
(Individual well sensitivity analysis + Combination well sensitivity analysis)
Water Injector
(Compare with without injectors)
Water Injector Sensitivity Analysis
Water Injection Timing Sensitivity Analysis
Water Injector Injection Period Sensitivity Analysis

36. Sensitivity Analysis Base Case Analysis (Individual Well)
Well B9 is the best individual producer (1.09%)

37. Base Case Analysis (Combination Wells)
Cases 1 2 3 4 5 B9
A15
A16 B8
A10
Total Cumulative Oil production,sm3
Rank
Recovery Factor, %
Case 2 (B9+A15+A16+B8) combination is the best (1.86%)

38. Water Injector
Injection wells used are the existing proposed wells given in FDP data pack (C2, C3, C4, C5 and C6).
Case with Injection wells are better (3.24%)

39. Water Injector Sensitivity Analysis
Combinations of water injectors are combined with the 5 producers.
The injector wells are removed one by one in the simulation.
Injector well which is furthest from the overall producer wells is eliminated first.

40. Water Injector Sensitivity Analysis (cont’d)
Combination of 5 producers with C4 as injector is the best (3.27%)

41. Water Injection Timing Sensitivity Analysis
Case
Inject at Beginning
Inject After 1 Year
Inject After 2 Years
Inject After 3 Years
Total Cumulative Oil Production sm3
Rank 1 2 3 4
Recovery Factor %
Water Injection at the beginning is the best (3.27%)

42. Water Injector Injection Period Sensitivity Analysis
The best base case is run for 5 years, 10 years, 20 years and 30 years respectively.
Case
5 Years
10 Years
20 Years
30 Years
Total Cumulative Oil Production sm3
Recovery Factor %
3.3
5.8
9.7
13.1
Water injection period of 30 years shows the best recovery (13.10%)

43. Reservoir Simulation Conclusion
The recovery factor of the field is expected to increase as the time period increases.
Due to time constraint for this project, the case is only run up till 30 years.
To get more recovery from the field, more wells need to be drilled and analysis is be made.
For a field with Billion standard cubic meter of oil, producing via water injection for 30 years with a recovery factor of 13.10% is considered very outstanding for a 5 wells producer.

44. Conclusions

45. Conclusions
The main objective was to develop the ideal plan in managing the natural resources in the Gullfaks field.
Due to the unavailability of data and lack of time, forced us to stop till reservoir engineering section only.
G&G- The field’s depositional environment consists basically of four main stratigraphic units with Tarbert and Ness being the target hydrocarbon bearing area.
Reserves- Significant reserves of hydrocarbons have been confirmed by A10, A15 and A16 wildcat wells, with estimated STOIIP of 2.05 BSTB, and GIIP of 180 Bscf using PETREL.

46. Conclusions Reservoir Engineering
Reservoir analysis shows the field is within normal hydrostatic pressure profile, with possible gas-oil and oil-water contact.
Simulation results show that the longer the production period with water injection, the higher the recovery factor. However, due to time constraint, the case is only run up till 30 years.
Considering single water injector, and 5 wells producer, 13.10% RF in 30 years is an outstanding value, hence probing more wells to be drilled and analysis be made.

47. THANK YOU

50. Back-Up

51. 2D Cross Section Imaging
Anticline
Hanging Wall
Fault
The structure shows a fault as indicated by the arrow and the existence of anticline, which makes it a suitable hydrocarbon reservoir trap. This 2D cross imaging will be compared to the static model that will be explained in the next section for accuracy comparison.

52. Facies: Good sand
Nw = 4.4
Now = 3
Ng = 6

53. Facies: Shaly sand
Nw = 4.4
Now = 3
Ng = 6

54. Facies: Fair sand
Nw = 4.4
Now = 3
Ng = 6

55. Purpose
Analyzing the performance of the reservoir, the potential reserve that can be recovered with the desired and most feasible recovery method.
Additional assurance in making a decision in reservoir management plan.
Objectives
To propose the most economical and feasible field development plan or strategy based of on the recovery factor and long term sustainability of the reservoir.
To predict the future performance and production profile of the field.

56. 5.3.3 Simulator Data Input
Equilibrium Data(Fluid Contacts)
OWC and GOC were determined from MDT data alone since it is the most reliable among the other data and other data were not sufficient.
GOC is 1701 meter and WOC is 1902 meter TVDSS.
Fluid Data
Obtained by using the PVTi software with the data given in the PVT report of the field.
Exported into PETREL 2012.
Core Data
Relative permeability and capillary pressure data obtained from the SCAL analysis studies of the core samples.
taken from well A10 depth intervals of m, m and m at a reservoir temperature of 220 degF.
3 different categories of sand or facies.
Good Sand (porosity fraction of and permeability of mD)
Shaly Sand (porosity fraction of and permeability of 16 mD)
Fair Sand (porosity fraction of 0.26 and permeability of mD).

57. 5.3.4 Dynamic Initialization
Original Hydrocarbon In Place
STOIIP simulated is Billion standard cubic feet.
Initial Reservoir Pressure and Fluid Equilibrium
The simulator initialized Gullfaks field with an initial pressure of psia.
Model was run for 5 years without any fluids being produced or injected into the reservoir.
Operating Constraints
Cases were run with the base conditions except for their specific sensitivities. The base conditions are:
STOIIP: 2.05 B STB
GIIP: 180 B SCF

58. Uncertainty Analysis Key concerns in uncertainties include;
Lack of well data and core data. (Uncertainty in rock properties)
This leads to poor correlation being obtained which affects the relative permeability since series of rock properties correlation are required in order to generate the representative relative permeability curve.
Bottom hole pressure (BHP)
The BHP data are also unrealistic for the first day of production. Take for instance well A10, the BHP at 0.00 hours was psia. After one hour of production and with a production rate of only STB/Day, the BHP dropped to psia. In other words a reservoir with STOIIP of STB and with a supporting Aquifer dropped 400 psia only after producing 3.75 STB.