Jackson Pola
Jackson is a petroleum engineer with more than ten years of experience in the oil and gas environment. He has strong expertise in dynamic reservoir modelling, upscaling, history matching, numerical simulation and optimisation of complex IOR/EOR processes, particularly in naturally fractured carbonate reservoirs.
He joined the Carbonate Reservoir Group at the Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK
He is a former regional chairman of the Society of Indonesian Petroleum Engineers (IATMI) Scotland and Northern Ireland, also a member of The Society of Petroleum Engineers (SPE), Society of Petrophysicists and Well Log Analysts (SPWLA), Indonesian Petroleum Association (IPA) and European Association of Geoscientists and Engineers (EAGE).
Address: Indonesia
He joined the Carbonate Reservoir Group at the Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh, UK
He is a former regional chairman of the Society of Indonesian Petroleum Engineers (IATMI) Scotland and Northern Ireland, also a member of The Society of Petroleum Engineers (SPE), Society of Petrophysicists and Well Log Analysts (SPWLA), Indonesian Petroleum Association (IPA) and European Association of Geoscientists and Engineers (EAGE).
Address: Indonesia
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coefficients, MINC shells, or the generation of recovery type curves, all of which have been suggested in the past to model more complex recovery processes. A careful examination of the fine-scale single- porosity model ("reference case") shows that a number of nested shells emerge, describing the advance of the concentration and saturation fronts inside the matrix. The number of shells is related to the required degree of refinement, i.e. the number of shells, in the improved MINC model. Using the results from a fine- scale single-porosity simulation to set up the shells in the MINC model is easy and requires only simple volume calculations. It is hence independent of the chosen simulator. Our improved MINC method yields significantly more accurate results compared to a classical dual-
porosity model, a MINC method with equally sized shells, or a MINC model with arbitrarily refined shells for a number of recovery scenarios that cover a range of matrix wettabilities and permeabilities. In general, improved results can be obtained when selecting five or fewer shells in the MINC. However, the actual number of shells is case-specific. The largest improvement is observed for cases when the matrix permeability is low. The novelty of our approach is the easy-to-use method to define shells for a MINC model to predict chemically enhanced oil recovery from naturally fractured reservoirs more accurately, especially in cases where the matrix has low permeability. Hence the improved MINC method is particularly suitable to model chemical EOR processes in (tight) fractured carbonates.
The Wakamuk field operated by PetroChina International (Bermuda) Ltd. and PT. Pertamina EP in Papua, with main of objective Miocene Kais Limestone. First production was commenced on August 2004 and the peak field produces around 1456 BOPD in August 2010. It was found that this reservoir system is considered as a complex system, until 2014 the cumulative of oil production was 2.07 MMBO less than 9% of OOIP. This performance indicates there are secondary porosity other than matrix porosity which has low average porosity 13% and permeability less than 7 mD.
Implementing chemical EOR in this case is the best way to increase oil production However, the selected chemical must be able to lower the IFT, reduce oil viscosity, and alter the wettability and thus a special chemical treatment named SeMAR has been proposed. Series of laboratory tests such as phase behavior test, core compatibility test, mixture viscosity, contact angle measurement, interfacial tension (IFT), imbibitions test and core flooding were conducted on Wakamuk field samples.
Based on the spontaneous imbibitions results for Wakamuk field core, formulation of SeMAR with compositional S12A gave oil recovery 43.94% at 1wt% concentration and maximum percentage of oil recovery 87.3 % at 3 wt% concentration respectively. In addition, the results for first scenario of core flooding test gave oil recovery 60.32% at 1 wt% concentration S12A and the second scenario gave 96.78% of oil recovery at concentration 3 wt% respectively. The soaking time of chemicals has a significant effect on the recovery and also higher of chemicals concentration used then larger area for wettability altered and therefore, higher oil recovery.
coefficients, MINC shells, or the generation of recovery type curves, all of which have been suggested in the past to model more complex recovery processes. A careful examination of the fine-scale single- porosity model ("reference case") shows that a number of nested shells emerge, describing the advance of the concentration and saturation fronts inside the matrix. The number of shells is related to the required degree of refinement, i.e. the number of shells, in the improved MINC model. Using the results from a fine- scale single-porosity simulation to set up the shells in the MINC model is easy and requires only simple volume calculations. It is hence independent of the chosen simulator. Our improved MINC method yields significantly more accurate results compared to a classical dual-
porosity model, a MINC method with equally sized shells, or a MINC model with arbitrarily refined shells for a number of recovery scenarios that cover a range of matrix wettabilities and permeabilities. In general, improved results can be obtained when selecting five or fewer shells in the MINC. However, the actual number of shells is case-specific. The largest improvement is observed for cases when the matrix permeability is low. The novelty of our approach is the easy-to-use method to define shells for a MINC model to predict chemically enhanced oil recovery from naturally fractured reservoirs more accurately, especially in cases where the matrix has low permeability. Hence the improved MINC method is particularly suitable to model chemical EOR processes in (tight) fractured carbonates.
The Wakamuk field operated by PetroChina International (Bermuda) Ltd. and PT. Pertamina EP in Papua, with main of objective Miocene Kais Limestone. First production was commenced on August 2004 and the peak field produces around 1456 BOPD in August 2010. It was found that this reservoir system is considered as a complex system, until 2014 the cumulative of oil production was 2.07 MMBO less than 9% of OOIP. This performance indicates there are secondary porosity other than matrix porosity which has low average porosity 13% and permeability less than 7 mD.
Implementing chemical EOR in this case is the best way to increase oil production However, the selected chemical must be able to lower the IFT, reduce oil viscosity, and alter the wettability and thus a special chemical treatment named SeMAR has been proposed. Series of laboratory tests such as phase behavior test, core compatibility test, mixture viscosity, contact angle measurement, interfacial tension (IFT), imbibitions test and core flooding were conducted on Wakamuk field samples.
Based on the spontaneous imbibitions results for Wakamuk field core, formulation of SeMAR with compositional S12A gave oil recovery 43.94% at 1wt% concentration and maximum percentage of oil recovery 87.3 % at 3 wt% concentration respectively. In addition, the results for first scenario of core flooding test gave oil recovery 60.32% at 1 wt% concentration S12A and the second scenario gave 96.78% of oil recovery at concentration 3 wt% respectively. The soaking time of chemicals has a significant effect on the recovery and also higher of chemicals concentration used then larger area for wettability altered and therefore, higher oil recovery.