KARAKTERISASI RESERVOIR ZONA DANGKAL UNTUK PENGEMBANGAN LANJUT LAPANGAN BERANI, CEKUNGAN KUTAI, KALIMANTAN TIMUR: STUDI KASUS RESERVOIR E11-4, E12-1 DAN E12-3 - Suardiputra, Aditya
Berani field is one of the mature field in Kutai Basin. It was discovered in April 1972 and have been produced for 40 years. Oil peak was reached in 1978 with production rate 58000 barrels oil per day. Decline of oil production is unavoidable. Today, average oil rate is 4000-4500 barrels oil per day. Field development strategy has been changed to develop gas production, since declining of oil production at Main zone and Upper zone. Tunu field was successfully to develop gas at shallow zone. It gave new perspective regarding gas potential in Berani shallow zone. Previously, Berani shallow zone was disregard due to it was hazard zone. Subsurface studies and reservoir characterization are compulsory in order to optimize gas production at shallow zone. Shallow zone divided into 2 zones which are Beta to MF2 zone and MF2 to U05 zone. it contains of unconsolidated multilayered sandstone. Focus of research are the biggest gas reservoir in shallow zone especially, reservoir E11-4, E12-1 and E12-3. Those reservoirs have not been optimally produced. 80 wells data including wireline logs, core interpretation data, pressure data, seismic interpretation result, and production data are used to do reservoir characterization. Core descriptions have been done by former geologist. 3 fasies association were identified from sandstone lithofacies, which are fluvial channel, distributary channel, delta front mouth bar. For electrofacies purpose, those facies association could be grouped into 2 types of deposit which are channel and bar. Logs pattern from that type of deposit would be used as reference to determine Shallow zone deposit. Depositional environment from those facies is fluvial-tidal dominated delta. The fluvial-tidal dominated system characterized by sand deposition in fluvial and tidal channels in the delta plain, and associated distributary channel and channel-mouth bar deposits in the delta front v???? ???? Based on wells corelation, channel deposit have trend NW-SE direction. Channels deposit at interval E12-1 and E12-3 developed at North part and disappeared at South part of research area. Meanwhile, Channels deposit at E11-4 was equally distributed at all area of the field. Geological model was built to display reservoir geometry and quality and also performed Initial Gas In Place (IGIP) calculation. it showed that reservoir geometry and quality are controlled by type of deposit (facies). Interval E12-1 and E12-3 at Northern part of the field have good sand thickness and porosity, average sand thickness is 5-10 m and average porosity is 21%. Meanwhile, in Southern part has low sand thickness and average porosity is 16-17%. Interval E11-4 has good sand thickness distribution with average thickness is 10-20 m and average porosity is 23- 27%. Total IGIP at three reservoirs are 20,79 bcf of gas. Geological model could be used as input for further development planning to define optimum infill wells. Based on evaluation showing that infill wells would be optimum at crest area in the North part.