Comprehensive preliminary reservoir studies and subsequent detailed geological analysis and surveillance programs were combined to plan and implement an efficient depletion scheme for the Pulai Field. A highly sophisticated three-dimensional mathematical model was developed to provide effective reservoir management. Model predictions shown an incremental recovery of 10.1% of the original oil-in-place through implementation of a gas injection scheme. Drilling of four additional wells in the two major sands provides an additional recovery of 7% of the original oil-in-place. The models will be periodically updated as production progresses and new information becomes available through progresses and new information becomes available through development drilling. Revised predictions from the updated models will be used in our continuing optimization of the Pulai Field.


The Pulai Field is located offshore Peninsular Malaysia in t he South China Sea about 160 miles east of Kuala Trengganu in 245 feet of water. The Field was discovered in October 1973 when Well No. 1 tested 2500 STB/D in the K30 sandstone. This well was drilled in the center of the field and encountered non-associated gas in the Group J (Tapis Formation (1)), oil and gas in Group K (Pulai Formation (1)) and oil in the Group L (Seligi Formation (1)).

Subsequently, three additional wells were drilled to delineate the structure and describe the hydrocarbon accumulation. Based on geologic and reservoir studies performed after the drilling of the exploratory wells, the 24 conductor "A" platform was installed in 1977. Production commenced in March 1978 and development drilling was completed in June 1979. Two additional exploratory wells drilled from a drill ship in 1980 and 1981 resulted in an extension of the proven portion of the field.

To provide effective reservoir management a comprehensive surveillance program was prepared and a three-dimensional, three-phase mathematical model was developed incorporating a detailed geological analysis and two years of historical performance.


The Pulai structure is an east-west trending asymmetrical anticline with approximately 750 feet of vertical relief at the level of the K10 sandstone. The highest bed dip is approximately 18 deg on the southern flank with an approximate bed dip of 5 deg to the north. The structure is 2-½ miles by 1 mile in area. On the western end of the field is a downthrown fault block known as Pulai Barat.

Figure 1 is an East-West structural cross-section showing a gas-oil contact at 38889 feet subsea and a water-oil contact at 4008 feet' subsea providing an oil column of 119 feet for the K10, K20 and K30 sandstones. Original reservoir pressure was 1735 psig at a datum of 3953 feet subsea.

The reservoirs encountered in Pulai consist of the J20/70, K10, K20, K30, K38, K50 and L10 sandstones. The J20/70 sandstone is a non-associated gas reservoir. The K20 and K30 sandstones are the major oil reservoirs bearing the 80% of the oil-in-place in Pulai. The oil columns are overlain by a large gas cap and underlain by an infinite type aquifer.

The Group K sandstones (K10 and K50) are of Miocene age and are interpreted to be of fluvial-alluvial origin. These Group K sandstones are generally fine to coarsed grained with occasional pebbly layers. A detailed geological analysis in the K20/30 pebbly layers. A detailed geological analysis in the K20/30 sandstones shown up to 21 shale streaks extending approximately 24 acres. The sands are well sorted and contain only small amounts of interstitial clay. Figure 2 is a stratigraphic cross section of the Pulai Field. Pulai Field.

Reservoir Rock Properties

Core analysis data in the K20 and K30 sandstones showed porosity values ranging from 18 to 31 percent and permeabilities ranging from 300 to 3000 md. The mean value of the porosity for a given well is expected to vary from 26.6 to 27.2 with a 95% level of confidence, Figure 3 shows the porosity-permeability relationship developed for the K20/30 sandstones. Average water saturation in the oil zone is estimated to be 24.2% in the K20 and 25.0% in the K30 sandstones.

Two phase relative permeability data for water-oil and gas-oil systems were obtained in the laboratory. These two-phase data are taken as a basis for estimating three-phase relative permeability three applying a probability model (3). In the model study, residual oil saturation was 30% for a water-oil system and 18% minimum attainable oil saturation was input as a parameter for three-phase relative permeability calculations.

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