Simulation Studies

Several sensitivity analyses were studied in order to come out with the optimum development strategy. These include:

1) Well type sensitivity 2) Well completion sensitivity 3) Well count sensitivity 4) Depletion strategy sensitivity 5) Peak rates sensitivity

6) Production performance and forecast sensitivity Well Type sensitivity

For the base case, the two existing wells in the exploration phases; Gelama Merah-1 and Gelama Merah-1 ST1 was used as the producer. The perforation intervals are optimized in such that it will perforate only at the oil interval of the reservoir which is in layer 9.0 to 9.1. Basically three runs were conducted and are summarized below as shown in Table 6.9:

Table 6.9: Base case results

Case 1 Case 2 Case 3

Producer Well Gelama Merah-1 Gelama Merah-1 ST1 completion and facilities costs associated with it. The recovery factor from the three base runs was relatively low (below 4%). Thus considering the operating costs and forecasted economic evaluations, new wells must be drilled as producers and new sensitivities runs will be made based on the new wells drilled.

In order to optimize the capital expenditure, optimum number of well were evaluated. Reservoir simulation study started with conventional vertical wells under natural depletion (ND) via gas cap expansion. 11 vertical wells yield 10.7%

recovery. Then the numbers were added to 13 wells and the recovery only increased by 0.9%. Due to the small increase of recovery, the drilling, completion and operating cost of these additional wells will not justify a good economic return. As such, simulation run with horizontal wells offers better economic potential. In the case of horizontal wells, the optimum well count achieved from the simulation results were 8 horizontal wells (RF=17.1%). The horizontal section of the wells was positioned in area with high oil saturation confirming with logs, in order to get better recovery. Figure 6.21 shows the Recover Factor (RF) and Field oil production rate (FOPR bbl/day) plotted against Time (yr).

Figure 6.21: FOPR (bbl/day) & RF vs Time (yr) for Horizontal and Vertical Wells

Well Completion sensitivity

Well completion strategy was evaluated in order to maximize the recovery and minimize coning problems which could yield to eventual shutting off the well.

Gelama Merah has around 42 meters of oil column. Given the relatively huge gas cap size and weak assessed aquifer support, conventional well production (Vertical wells) could be susceptible to gas coning due to high pressure drop. In addition, more wells were required to achieve good recovery from multiple reservoirs. The best recovery obtained from the simulation was achieved with 8 horizontal wells. Adding more wells did not increase the recovery significantly, while reducing the number of wells decreased the optimal recovery. The wells were strategically placed at bottom one-third of the oil column in order to avoid early gas breakthrough or Localized gas clasping and preserving the reservoir drive energy as much as it could. The range of horizontal section used in the simulation was from 200 meters to 400 meters. Figure 6.22 below shows the Field oil production total (FOPT bbl) plotted against Time (yr).

Figure 6.22: FOPT (bbl) vs Time (yr) for Horizontal and Vertical Wells

Well Count sensitivity

In order to optimize the capital expenditure, optimum number of wells was evaluated. Wells with the lowest range of recovery were deleted one by one. Some of the remaining wells were repositioned depending on the outcome of the simulation result in order to try to get a better recovery. In the case of horizontal wells, the optimum well count achieved from the simulation results were 8 horizontal wells (RF=17.1%). Referring to Figure 6.23, adding additional well did slightly increase the recovery factor but insufficiently justify the cost of drilling the extra well, thus not economically attractive to further add more wells. While reducing the number of wells to less than 8 wells, it decreases significantly the optimal oil recovery. Based on this sensitivity analysis, it is more economically feasible to develop this field with 8 horizontal wells. Figure 6.23 below shows a plot of Field oil production rate (FOPR bbl/day) and Recovery Factor plotted against Time (yr).

Figure 6.23: FOPR (bbl/day) & RF vs Time (yr) for 7, 8 and 9 Horizontal Wells

Depletion Strategy sensitivity

In an effort to improve oil recovery and to control the steep decline of pressure drop due to gas cap expansion, gas and water injection scenarios were investigated. For all the cases, the existing exploration well; Gelama Merah-1 was utilized as one of the injector well. Reservoir pressure maintenance strategy through water injection (WI) and gas injection (GI) schemes were investigated, using the horizontal wells completion as base case. The simulation run shows that obtainable recovery factor through water injection (in the case of 3 WI wells and voidage replacement ratio, VRR=1) equal to 19.1%. With the gas injection scheme (in the case of 2 GI wells, VRR=1 and no gas production restriction), the oil recovery factor reaches 21.4%.

1) Gas Injection

For the case of gas injection, huge amount of gas is needed to be injected in order to maintain the VRR of one (1). Few cases were investigated by applying no limits on injection which resulted in the injection pressure at sand face exceeding the fracture pressure of the formation. Nevertheless,

sensitivity study was done to check the possibility of applying gas injection to the reservoirs.

The oil recovery factor reaches 21.4% for the case of gas injection scheme (with 2 injectors and no gas production restriction) with the injection pressure being limited to 2500 Psia to ensure the formation pressure not to exceed the fracture pressure. Even though gas injection provides a better recovery factor, but the amount of gas required to be injected is phenomenal (up to 110 MMscf/d), thus making this option economically unattractive.

2) Water Injection

Similarly to gas injection, water injection also yielded a better recovery than Natural depletion with a Recovery factor of 19.1% (3 injectors). If oil production is not limited, bigger volume of water is needed for injection to maintain the VRR of one. Again precautionary measures were taken to ensure the formation pressure does not exceed the fracture pressure due to injection. The recovery factor obtained for water injection is only slightly higher than the natural depletion strategy, but huge amount of additional investment would be required on the 3 water injector wells and water injection facilities, which makes it economically unattractive.

Figure 6.24 shows the simulation results that illustrates the production and recovery implications of different strategies.

Figure 6.24: FOPR (bbl/day) & RF vs Time (yr) for GI, WI and ND

Table 6.10: Simulation results on production and recovery of different depletion cases

Case

Peak Oil Rate (BOPD)

RF (%)

Incremental NPV @ 10%

(RT, USD Million 2010) Remarks Natural

Depletion 9000 17.1 14.2 Base Case

Water

Injection 9000 19.1 -3.4 Uneconomical

Gas

Injection 9000 21.4 -12.7 Uneconomical

Based on the simulation results and the anticipated additional capital expenditures, horizontal completion with Natural depletion is concluded as the optimum development option and the most economically attractive.

Peak rates sensitivity

Sensitivity study was done on establishing the suitable peak rate for the oil production. First simulation run was done without putting any limit to the oil rate and gas rate. Two peak rates were studied in this analysis (7000 and 9000 bbl/day). The optimum peak rate considered for this simulation run is 9000 bbl/day to ensure maximum revenue to be earned in the early stages of field life because cash flows at later stages are discounted heavily. Figure 6.25 below shows a plot of Field oil production rate (FOPR bbl/day) and Recovery Factor plotted against Time (yr) for the 2 peak rates studied.

Higher drawdown causes high production of gas-cap gas due to gas coning. To arrest this issue, several sensitivities on peak rates and gas production were done.

The optimum peak rate was found to be 9000 BOPD with gas rate limitation of not more than 30 MMSCF/day. Figure 6.26 shows the pressure decline between with no limit on production of gas and the pressure decline when gas production is limited to 30 MMSCF/day. Limiting the total gas produced will decide on the size of compressor to be designed and a smooth trend for reservoir pressure decline could be obtained.

Figure 6.25: FOPR (bbl/day) & RF vs Time (yr) for 7000 and 9000 bbl/day

Figure 6.26: FPR (psia) vs Time (yr) for No Limit and Limit of 30MMSCF/day

Production performance and forecast sensitivity

First oil will be produced at a scheduled date of May 2015. The following Table 6.11 and Figure 6.27 shows the production forecast of Gelama Merah reservoir for 15 years and expected to produce up to a total of 14.96 MMbbl of oil (until the end of PSC contract). With a plateau rate of 9000 bbl/day of oil for 2 years is to be expected. The high plateau rate is imposed in order to produce as much oil as possible in the early years to reduce the payback period. Table 6.11 below shows the production profile of Gelama Merah.

Figure 6.27: FOPR (bbl/day) & RF vs Time (yr) for 9000 bbl/day

Table 6.11: Production Profile for Gelama Merah

Year Oil Rate Bbl/Day

GOR Scf/Stb

Gas Rate MMscf/Day

Watercut Fraction

1 9000 4133 37.25 0.052

2 9000 7636 68.83 0.287

3 5002 6511 32.57 0.585

4 3232 2817 9.10 0.680

5 2162 2129 4.60 0.753

6 1601 1953 3.12 0.793

7 1299 1811 2.35 0.812

8 1052 1699 1.78 0.827

9 900 1642 1.47 0.835

10 765 1546 1.18 0.841

11 700 1503 1.05 0.838

12 601 1571 0.94 0.844

13 522 1441 0.75 0.847 under natural depletion with oil production reaching peak rate of 9000 oil bbl/day.

To achieve the reservoir objective, the strategies discussed below will be implemented.

Development and operating strategies

• Reservoir will be produced with horizontal wells in order to maximize the contact with reservoir and minimize drawdown to avoid gas coning/cusping and also water coning. Due to the relatively huge gas cap size, gas coning is a more prominent issue than water coning and thus, the horizontal section of all the wells will be completed approximately bottom one-third of the oil column.

• Since the reservoir will be depleted naturally, the wells need to be strategically placed with optimum well spacing to ensure efficient reserves drainage.

• Impose GOR limit or prioritize production based on GOR performance.

Gelama Merah has relatively large gas cap. From production performance (Table 6.11), the GOR is quite high. Thus, GOR limit shall be imposed for the purpose of controlling gas production. This is to minimize gas coning/cusping in order to conserve the reservoir energy and minimizing the reservoir pressure decline.

• Simulation study shows that Gelama Merah produced quite a lot of water from the first day of production. Hence close monitoring of water production is essential to provide early corrective measures to prevent excessive water production in early field life. Therefore it is essential to shut-in the wells