Summary
The giant Handil field comprises more than 500 hydrocarbon accumulations in structurally stacked and compartmentalized fluvio-deltaic sands. Most of the accumulations consist of a large column of saturated oil underlying a gas cap, trapped in reservoirs with good rock properties, and produced by water injection or strong natural waterdrive.
In 1995 five reservoirs representing nearly one-fifth of the field's total original oil in place (OOIP) - and which had reached their final stage of waterflood development (58% of the total oil in place had already been produced) - were submitted to further development with lean-gas injection to increase the ultimate oil recovery. To date, after 3 years of gas injection, the recovery factor for these five reservoirs has increased by 1.2% of the oil initially in place, and the project is considered both a technical and an economic success.
The predominant drive mechanism with lean-gas injection has been confirmed by field data. The previous decline of oil production has been stopped, and the oil rate is now stabilizing. The main monitoring challenge has been the control of gas cycling for most of the producers, particularly during periods of higher injection rates, to compensate for low injection periods imposed by gas availability.
The very close monitoring of well and reservoir performance, the numerical simulation, and material-balance studies have helped provide a better understanding of the mechanisms involved and have led to a revised and more efficient policy to maximize oil production.
The experience gained and the analysis of this 3-year-old project gives us the confidence to pursue the extension of the lean-gas injection development to other Handil field reservoirs.
Introduction
Handil is a giant oil field located in the Mahakam Delta of the island of Borneo, Indonesia (Fig. 1). The structure of the field is a simple anticline, 4 km long and 3 km wide, with a main east-west fault dividing the north and south areas (Fig. 2).
The geology is complex; the field comprises more than 500 hydrocarbon accumulations, stacked between 300 m to 4000 m subsea, trapped in channel-sand and sand-bar reservoirs deposited in a fluvio-deltaic environment of Miocene age (Fig. 2). Vertically, the field has been subdivided into a shallow zone, grouping the accumulations from 300 to 1500 m subsea; a main zone, between 1500 and 3000 m subsea; and a deep zone with the accumulations below 3000 m subsea. Approximately 300 oil accumulations are found in the shallow and main zones, while the 200 gas accumulations lie mostly in the deep zone.
The reservoirs are of excellent characteristics, with permeabilities ranging from 10 to 2000 md, porosities of approximately 25%, and connate water saturations of about 22%. Within a given reservoir, the vertical permeability is of the same order as the horizontal permeability.
Most of the oil accumulations consist of a large column with more than 100 m of saturated oil underlying a gas cap, the relative size of which is very variable. The structural dip ranges from 5 to 12°, down to the aquifers generally connected in the western and eastern sectors. The aquifers are generally very strong in the shallow zone, and rather weak in the main and deep zones.
The initial pressure regime is hydrostatic, while the temperature gradient is 0.03°C/m. The oil density varies between 31 and 34°API from the shallow to the main zone. Oil formation volume factor is 1.1 to 1.4 v/v, dissolved gas-to-oil ratio is 50 to 100 v/v, oil viscosity is 0.6 to 1.0 cp, and gas formation volume factor ranges from 0.005 to 0.01 v res/v surface.
Production History
Oil production started in 1975 under natural depletion drive. Shortly afterward, the accumulations of the main zone, which benefited from a weak aquifer at best, were submitted to development by peripheric water injection.
Water injection eventually became the depletion-drive mechanism for the equivalent of 65% of the field's OOIP. Field production peaked at 180,000 BOPD in 1982, out of which 128,000 BOPD were being produced, thanks to water injection (Fig. 3).
The combination of favorable reservoir and fluid properties, along with intensive reservoir studies and monitoring, has made the waterflood development very successful.
Handil has now become a very mature field with more than 330 wells drilled, resulting in a well spacing of 300 m. Most of the wells have dual string completions with up to five packers.
At the end of 1995, five main-zone reservoirs, which represented about 20% of the field's total OOIP and which had reached the end of their development by waterflood (with an average oil recovery factor of 58%), were submitted to further development by crestal injection of lean hydrocarbon gas.
Gas-Injection Studies
Extensive studies had been carried out as recently as the early 1980's to evaluate enhanced oil recovery (EOR) developments of the Handil field. The most economically attractive option was found to be the reinjection of associated gas.
Geo-electrical mapping and groundwater potential zoning in some selected pockets of Baromura hill of Tripura (India)
