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Reservoir Report

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  1 CHAPTER 1: INTRODUCTION This section presents the reservoir engineering studies for development of Berlian East field, prior the previous Geology & Geophysics assessments in Phase I of Field Development Plan (FDP). Well test data, PVT data; fluid composition data are analysed to confirm the reservoir condition. Reservoir performance, well locations, well numbers, depletion strategy from natural depletion and water injection depletion drive until tertiary recovery by Enhanced Oil Recovery (EOR) are being analysed in this session. Berlian East (BE) field that is located some 25km offshore Terengganu, Peninsular Malaysia is the reservoir of interest in this field development plan (FDP) with average water depth of 76m. The wells were remained shut-in due to low profitability until the recent interest in the potential of the field. G&G evaluations had been implemented and the following tables summarize the estimation of the oil in place:   Sand STOIIP (MMStb) M 2/3 46.7 M 7/8 119 M 9/14 35.7 M15 5.2 Total   206.6 Table 1: Summary of STOIIP estimation from G&G assessment 1.1 OBJECTIVES    To estimate the production forecast for natural depletion drive and water injection drive    To calculate the number of production wells    To establish a reservoir management plans and EOR proposal for the field  2 CHAPTER 2: RESERVOIR ENGINEERING 2.1 RESERVOIR DATA From the data obtained, this session will give an overview about the important reservoir data used in the reservoir studies. These data includes PVT analysis data of  bottomhole fluid sample, hydrocarbon analysis on separator liquid and gas, formation water analysis and well test results. The summary of the reservoir fluids and properties are shows in the table below: Properties Value Reservoir Datum Depth (mss) 1300 Reservoir Pressure (psig) 1854 Bubble Point Pressure (psig) 1332 Reservoir Temperature ( o F) 215 Reservoir Contact (mss) 1358 (WOC) Porosity, fraction 0.27 - 0.29 Permeability, mD 118 - 900 Oil Formation Volume Factor (rb/stb) 1.43718 Oil API o  35-42 Oil viscosity (cp) 1.76 Solution Gas ratio (scf/stb) 1400 Table 2 : Reservoir Fluids and Rock Properties 2.1.1 PVT Analysis The PVT data used in the study was obtained from bottom hole fluid sample taken in well Berlian East-1 from the M2A sands. Since there is limited source of fluid sample and since all the M sand units were formed almost at the same geological time, this data is assumed to be the representative of fluids in all M units. At datum depth of 1300 mss, the reservoir pressure is 1854 psig and temperature measured is 215 o F. Table 3  below summarizes the PVT analysis of the M2A fluid sample.  3 * : bubble point pressure at reservoir temperature ** : initial reservoir pressure at datum Table 3 : PVT Analysis Results of BE-1 M2A Sand As shown in table above, it is observed that the bubble point pressure, P  b  is 1332 psig while the initial reservoir pressure (Pr) measured at datum is 1854 psig. As the reservoir  pressure (Pr) is higher than the bubble point pressure (Pb), the situation is termed undersaturated reservoir and the oil is act like a single phase liquid. Since the oil is undersaturated, this implies that it could dissolve more if the latter were available. The bubble  point pressure is determined as the pressure where the relative volume exceeds unity or where the gas solution ratio started to change. For this case, the initial value of the solution gas oil ratio (Rs) remains constant at 1400 scf/stb until the pressure drops to the bubble point  pressure of 1332 psig, when the oil becomes saturated.   Gas saturation continues to increase until it exceeds the critical gas saturation. Figure below explained the gas solubility condition. Pressure (psig) Bo (rb/stb) Bg (rcf/scf) Oil viscosity (cP) Gas viscosity (cP) Rs (scf/stb) Bt (rb/stb) 6000 1.3000 1.300 5000 1.3428 1400.000 1.342 4000 1.3728 2.61 1400.000 1.372 3000 1.4028 2.31 1400.000 1.402 2000 1.4328 2.04 1400.000 1.432 1854** 1.43718 1.76 1400.000 1.437 1660 1.4430 1.70 1400.000 1.443 1332* 1.4500 0.0116 1.65 0.0171 1400.000 1.450 1077 1.3731 0.0147 1.72 0.0168 1131.927 5.313 817 1.2951 0.0199 1.8 0.0165 858.6670 12.067 548 1.2144 0.0305 1.86 0.0163 575.9480 26.348 270 1.131 0.0624 1.92 0.016 283.7700 70.783 0 1.0500 2.04 0.0151 0.000  4 Figure 1: Gas Solubility Condition . When pressure continues to decline over the time, Rs continued to decrease as gas is dissociated to leave the oil behind. Thus, it is crucial to maintain the reservoir pressure above  bubble point to prevent the gas liberated out from solution and resulting in high gas oil ratio (GOR). Other than that, it is also observed that the viscosity of the oil decrease when the  pressure is higher; however, at pressure above bubble point, the viscosity increase with increase in pressure. Figure 2 : Bo vs Pressure
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