CARBONATE RESERVOIR MODELING BASED ON PETROPHYSICAL ROCK TYPE ANALYSIS OF UPPER BERAI FORMATION, KERENDAN FIELD, WEST KUTAI BASIN, CENTRAL KALIMANTAN - Setiawan Hasibuan (NIM 22012012), Syahrial
Kerendan field is one of gas and condensate field which is located on west side of Kutai Basin, Central Kalimantan, and producing hydrocarbon from carbonate interval of Upper Berai Formation. The discovery was at 1982 by drilling of exploration well Kerendan- 1 which followed by several other exploration and development well. The development stage resulted conclusion that carbonate reservoir of Upper Berai has high heterogenity due to diagenetics and depositional feature so it is necessary to characterize the reservoir based on petrophysical rock type to understand geological control of reservoir distribution. Carbonate reservoir in Kerendan Field is reefal carbonate shaped rounding isolated platform which is deposited shallow marine condition during Oligosen and grew aggradationally. Deposited lithofacies which is consisted of five lithofacies are: (1) coralinered algal boundstone, (2) skeletal grainstone, (3) coraline-red algal pack-wackestone, (4) large foraminiferal pack-wackestone, and (5) argillaceous foraminiferal wacke-mudstone. Those five lithofacies deposited in four facies association: (1) platform interior, (2) platform rim, (3) platform slope, and (4) basinal shale. This formation has been through diagenetic events as follows: early marine, late marine, and subsurface diagenesis. Based on hydraulic flow unit method, reservoir in this field can be distinguished into five petrophysical rock type (PRT), they are: PRT 1 (touching vug pores and interparticle micropore patchy association), PRT 2 (touching vug pores, interparticle micropore patchy, and intercrystaline macropore patchy association), PRT 3 (touching vug pores, separate vug pores, interparticle micropore patchy, and intercrystaline mesopore patchy association), PRT 4 (separate vug pores, interparticle micropore patchy, and intercrystaline microporosity patchy), and PRT 5 (separate vug pores and mudstone microporosity uniform). Those PRT proceeded from specific diagenetic factor and depositional setting which is resulted specific porosity and permeability. Reservoir modeling of facies association, porosity, and PRT which are controlled by well data in the end delivered better permeability calculation compared to conventionally used permeability calculation with petrophysical equation such as Coates-Dumanoir (Coates & Dumanoir, 1974) after validated by core data.