Microporosity and Reserves: Lessons Learned in the Lisburne Field, North Slope, Alaska

John Kaldi
CO2CRC, Australian School of Petroleum, University of Adelaide, Adelaide, Australia

Early well log and Drill Stem Test (DST) analyses resulted in optimistic original oil in place (OOIP) values and robust reserves estimates in the Carboniferous Lisburne Group in the Lisburne Field, North Slope, Alaska. Facilities built to handle the fluid throughput expected based on these results fell short of their targets. Several years of continued studies concluded that less than 10% of close to 2 billion barrels OOIP are recoverable.

So what happened? The Lisburne Group comprises four major carbonate rock types, including fractured dolomite, moldic limestone, argillaceous mudstone and microporous grainstone. The microporous rock comprises more than 60% of the reservoir and the effects of this microporosity were not fully appreciated on the initial log and test data. Logs typically showed “clean” gamma ray, good porosity and high resistivity. The microporous rocks have high porosities (5-18%) but low permeabilities (less than 0.5 md). A thick hydrocarbon column with buoyancy pressures adequate to saturate even the micropores resulted in high resistivity log response. However, the recovery efficiency of these rocks is low, resulting in limited contribution to production. Production logs indicated that the intervals yielding the majority of oil were the fractured dolomites, which unfortunately comprised the lesser portion of total rock volume. Long-term DST's indicated typical dual porosity characteristics, with an initial production plateau followed by steep decline.

Early reserves estimates were based on high porosity and hydrocarbon saturation values and high recovery factors (RF) from reservoir simulation models that included an assumption of water flood. A pilot water flood resulted in rapid water breakthrough (through fractured dolomites) and very low sweep efficiency of the microporous intervals.