Reservoir Simulation Study

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).

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

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

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

Base Case Analysis (Combination Wells) Cases 1 2 3 4 5   B9 A15 A16 B8 A10 Total Cumulative production,sm3 3356525 6048778 5707355.5 5013456 3546478.75 Rank Recovery Factor, % 1.0296089 1.85545337 1.75072255 1.53786994 1.08787692 Case 2 (B9+A15+A16+B8) combination is the best (1.86%)

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%)

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.

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

Water Injection Timing Sensitivity Analysis Case Inject at Beginning Inject After 1 Year Inject After 2 Years Inject After 3 Years Total Cumulative Production sm3 10673770 5756665.5 4093237 3569446 Rank 1 2 3 4 Recovery Factor % 3.274162577 1.765848313 1.255594172 1.094922086 Water Injection at the beginning is the best (3.27%)

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 Production sm3 10673770 18985820 31700354 42648020 Recovery Factor % 3.3 5.8 9.7 13.1 Water injection period of 30 years shows the best recovery (13.10%)

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.

Back-Up RE

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.

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. Good Sand (porosity fraction of 0.275 and permeability of 49.326mD) Shaly Sand (porosity fraction of 0.219 and permeability of 16 mD) Fair Sand (porosity fraction of 0.26 and permeability of 239.4 mD).

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