1. Nur Syazwani Moktar12152 Kong Fook Ann12618 Teoh Kheng Keat12879 Muhammad Syamim Hussain12764 Mohamed Saifullah Sirajudin12661 Arunan Isvaran12534 Adnane Mohamed Abdellahi Zeine13442 Malik Muhammad Humza15205 GROUP 13

2. 1. Introduction 2. Geology & Geophysics 3. Petrophysics 4. Reservoir Engineering 5. Conclusions

3. 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 300-400 m. Location of Gullfaks field in the North Sea

4. 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. 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. Petroleum System 2D Cross Section Imaging Stratigraphic Correlation Depositional Environment Volumetric Estimation

7. 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 50- 250 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 2-2.5 % Petroleum System

8. 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 300-2000 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. Petroleum System

9. 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. Petroleum System

10. 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 Petroleum System

11. 2D Cross Section Imaging

12. Anticline Hanging Wall Fault 2D Cross Section Imaging

13. Unconformity Thinning Strata S-NThickening Strata S-N Stratigraphic Correlation

14. Depositional Environment

15. 3D Static Modeling Isochore Points on Static Model Static Model Thickness Defined (Lateral View)

16. Volumetric Estimation

17. Breakdown of STOIIP Based on Layers

18. Breakdown of GIIP Based on Layers

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

20. ZoneInterpretationLog Section Top Tarbert - Tarbert 2 Depth: 1805.5 m to 1812.5 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 Depth: 1812.5 m to 1823.3 m In this zone, sandstone interbedded with silts.  Sand – 61%  Silt – 39% Tarbert 1 – Top Ness Depth: 1823.3 m to 1852.8 m Shale in this particular zone has almost the same percentage as silt.  Shale – 53%  Silt – 47% Top Ness – Ness 1 Depth: 1852.8 m to 1894.1 m This zone is mainly sandstone with 93%.  Sand – 93%  Silt – 7% Ness 1 – Top Etive Depth: 1894.1 m to 1943.6 m In this zone, shale shows a very high percentage.  Shale – 99%  Sand – 1% Lithology

21. Oil POWC Water Fluid Types & Fluid Contacts

22. 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 Pressure Plot

23. Zone GR log (average) Volume of shale (%) Interpretation Top Tarbert - Tarbert 2 53.724.4 Tarbert 2 - Tarbert 1 68.538.3 Tarbert 1 - Top Ness 98.166.0 Top Ness - Ness 1 53.424.1 Ness 1 - Top Etive 127.193.2 Volume of Shale (Vsh)

24. ZoneAverage Shale Volume (%) Top Tarbert – Tarbert 210.1 Tarbert 2 – Tarbert 134.6 Tarbert 1 – Top Ness60.2 Top Ness – Ness 127.3 Ness 1 – Top Etive90.4 ZoneAverage Effective Porosity Top Tarbert – Tarbert 20.184 Tarbert 2 – Tarbert 10.187 Tarbert 1 – Top Ness0.160 Top Ness – Ness 10.178 Ness 1 – Top Etive0.108 Volume of Shale (Vsh) Porosity (Ø)

25. Reservoir Fluid Studies SCAL

26. Reservoir Fluid & SCAL Reports Reservoir Fluid Report: Constant Composition Expansion Test (CCE) Differential Liberation Test (DLE) Separator Test Swelling Tests for CO 2 and N 2 SCAL Report: Capillary Pressure Test (Oil-Water) Relative Permeability Test (Gas-Oil, Oil-Water)

27. 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 o F Constant Composition Expansion Bubble-point Pressure: 2516.7 psia Differential Liberation Test Oil Formation Volume Factor: 1.1 bbl/STB Solution Gas-Oil Ratio: 1.1342 Mscf/STB Oil Density: 45.11 lb/ft 3 Reservoir Fluid Viscosity Oil Viscosity: 1.33 cp

28. Phase Plot for Gullfaks DST #1 Phase Plot

29. Relative VolumeLiquid Density Oil Relative VolumeGas Gravity Reservoir Fluid Properties

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

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

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

33. Reservoir Simulation Studies

34. Reservoir Drive Mechanisms and Energy Plot Has Gas-Oil Contact and Water-Oil Contact (might have gas cap drive+water drive). Initial reservoir pressure 2516 psia and bubble point pressure of 2516.7 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).

35. 3D Geological Static Model Export 3D static model was developed using PETREL 2012

36. Base Case Analysis (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 Sensitivity Analysis

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

38. Case 2 (B9+A15+A16+B8) combination is the best (1.86%) Base Case Analysis (Combination Wells) Cases12345 B9 A15 A16 B8 A10 Total Cumulative production,sm3335652560487785707355.550134563546478.75 Rank51234 Recovery Factor, % 1.02960891.855453371.750722551.537869941.08787692

39. 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%)

40. 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.

41. Combination of 5 producers with C4 as injector is the best (3.27%)

42. Water Injection Timing Sensitivity Analysis Water Injection at the beginning is the best (3.27%) CaseInject at Beginning Inject After 1 Year Inject After 2 Years Inject After 3 Years Total Cumulative Production sm3106737705756665.540932373569446 Rank1234 Recovery Factor %3.2741625771.7658483131.2555941721.094922086

43. Water Injector Injection Period Sensitivity Analysis The best base case is run for 5 years, 10 years, 20 years and 30 years respectively. Water injection period of 30 years shows the best recovery (13.10%) Case5 Years10 Years20 Years30 Years Total Cumulative Production sm310673770189858203170035442648020 Recovery Factor %3.35.89.713.1

44. 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 0.326 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.

45. 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 2444.835 psia. After one hour of production and with a production rate of only 89.933 STB/Day, the BHP dropped to 2053.058 psia. In other words a reservoir with STOIIP of 393.92 million STB and with a supporting Aquifer dropped 400 psia only after producing 3.75 STB.

47. 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.

48. 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. Conclusions

49. THANK YOU

50. Back-Up RE

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

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

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

54. Purpose i.Analyzing the performance of the reservoir, the potential reserve that can be recovered with the desired and most feasible recovery method. ii.Additional assurance in making a decision in reservoir management plan. Objectives i.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. ii.To predict the future performance and production profile of the field.

55. 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 1794-1796 m, 1824-1827 m and 1903-1905 m at a reservoir temperature of 220 degF. 3 different categories of sand or facies. i.Good Sand (porosity fraction of 0.275 and permeability of 49.326mD) ii.Shaly Sand (porosity fraction of 0.219 and permeability of 16 mD) iii.Fair Sand (porosity fraction of 0.26 and permeability of 239.4 mD).

56. 5.3.4 Dynamic Initialization Original Hydrocarbon In Place STOIIP simulated is 0.326 Billion standard cubic feet. Initial Reservoir Pressure and Fluid Equilibrium The simulator initialized Gullfaks field with an initial pressure of 2516.7 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