Managing Fluid Saturation Uncertainties in Low Resistivity Gas Reservoirs: A Case Study from the "X" Field in the Baram Delta, Offshore Sarawak, Malaysia
- Abraham J. S. Simanjuntak (JX Nippon Oil and Gas Exploration (Malaysia) Ltd.) | Johnny Y. C. Jin (JX Nippon Oil and Gas Exploration (Malaysia) Ltd.) | Gyuhwan Jo (JX Nippon Oil and Gas Exploration (Malaysia) Ltd.) | Steven M. Barker (JX Nippon Oil and Gas Exploration (Malaysia) Ltd.) | Quach Thu Vu (JX Nippon Oil and Gas Exploration (Malaysia) Ltd.)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- SPWLA Asia-Pacific Regional Conference, 1-4 March, physical event not held
- Publication Date
- Document Type
- Conference Paper
- 2020. held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors
- 14 in the last 30 days
- 14 since 2007
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The "X" gas field offshore Sarawak (Malaysia) encountered a number of low resistivity low contrast (LRLC) reservoirs during its exploration and appraisal stages back in 1990's. Subsequently, development wells drilled to produce gas from these reservoirs since 2003 have been producing gas with no water breakthrough (very low water production) after sixteen (16) years of production up to date.
One of the uncertainties in the initial petrophysical evaluation of these sands is formation water salinity. Numerous water samples have been collected during drill-stem-test (DST) and throughout the development phase. However, salinity measurements of these samples indicate a wide range between 8,400 – 214,000 ppm (NaCl eq.). These samples are considered unrepresentative due to mud filtrate contamination or dominated by condensed water from gas solution. Moreover, none of the exploration and appraisal wells penetrated definitive water sand (aquifer). This further complicates our understanding of the formation water salinity as no definitive formation water sample is available.
Initial water saturation computation (using resistivity log data) over these sands had been performed using relatively low/brackish formation water salinity input (15,000 – 20,000 ppm). This scenario resulted in relatively high water saturation (Sw) which did not conform with DST results where no formation water production had been observed.
Further review of core capillary pressure (Pc) data indicates that the irreducible water saturation (Swirr) over these sands is lower than the resistivity-based Sw. This somewhat suggests the formation water salinity input for the resisitivity-based Sw may be overly pessimistic as it yields higher initial Sw than the core Swirr.
An updated petrophysical evaluation has been performed using a different water salinity parameter to reconcile the resistivity-based Sw with core Swirr data obtained from Pc measurements. Core porosity, permeability and Pc datasets have also been revisited to derive a new set of rock type groups with its associated saturation height function (SHF) models. The updated petrophysical study demonstrates better reconciliation between log and corebased fluid saturations. This study also suggests considerable improvement in hydrocarbon saturation as well as better understanding in fieldwide hydrocarbon distribution across these low resistivity sands with optimized prediction of water breakthrough time and infill drilling opportunities.
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