Publications

The Jambi Merang Block is located in South Sumatra Indonesia. The PSC involves development of two fields, Pulau Gading and Sungai Kenawang. A Joint Operating Body (PERTAMINA - Hess Jambi Merang) will develop and operate the fields. In 2006, two wells in different fields in the Jambi Merang project were drilled with drill stem tests (DST) and fluid sampling. DST results demonstrated a wide variation in condensate-gasratio (CGR) from 32 to 92 BBL/MMCF in one field and 13 to 65 BBL/MMCF in the other. Pressure-Volume-Temperature (PVT) results indicate less than 1% reservoir condensate dropout is expected. However, this does not support the wide range in DST CGR. The purpose of this paper is to present, 1) the factors contributing to the variation in CGR, 2) the methodology for expected impact of condensate dropout, 3) the natural gas liquids (NGL) yield prediction during depletion and 4) lessons learned from sampling. This work supports a 24% increase NGL production. The workflow included, 1) choosing representative samples and updating reservoir fluid characterizations, 2) DST interpretations and 3) constructing simulation models to match interpretations. The simulation model matched DST rate and variation CGR, determined the expected condensate bank impact and determined the expected fluid composition and NGL yields during the field depletion. Although the condensate dropout is less than 1%, it can accumulate (bank) near the wellbore. Dew point pressure and initial reservoir pressure are similar therefore dropout starts at initial production. This dropout changes the NGL yield and can impact productivity and recovery. To estimate the impact, a radial single well, multi-layer compositional simulation model was constructed and history matched to DST data. Sensitivities to permeability, skin, gas composition and drawdown were performed. The model demonstrates little impact of condensate banking on productivity and recovery and the dependency of CGR from DSTs on separator conditions. Reservoir temperature has an impact on fluid behavior and NGL yields are higher than previously modeled, decreasing as the fields are depleted. In addition to the high reservoir temperatures, liquids formed above the critical saturation are carried by gas velocity to the wellbore due to high reservoir permeability. Therefore gas production rate has little impact on liquid or gas recovery.