Multiple Packer Completions In The Attaka Field
Authors: Badon H.B. , Nellis W.E. 
Published: December 2007

The Attaka Unit, operated by Union Oil Company of Indonesia on behalf of Pertamina and Japex Indonesia Limited, is located 13 miles off the East Pertamina and Japex Indonesia Limited, is located 13 miles off the East Coast of Kalimantan, Indonesia, 90 miles north of the coastal city of Balikpapan (Fig. 1). The structure is a domal anticline complicated by transverse faults. The stratigraphy is predominantly a sequence of sand and shales reflecting in broad aspect, a transition from marine environments of deposition to shoreline and deltaic environments as the basin filled.

The field was discovered in August. 1970 with the Attaka Well Number 1-A. Seven additional wells were drilled to define the limits of the field. Construction of offshore platforms, onshore process and oil storage facilities, and pipeline platforms, onshore process and oil storage facilities, and pipeline installation commenced in December, 1971. Initial oil production began in November 1972, 27 months after the production began in November 1972, 27 months after the discovery of the field. The initial producing rate from the nine wells on Platform A was 20,000 BOPD. By November, 1973, the original projected producing rate of 100,000 BOPD was attained from the field when the sixth Attaka-Unit platform was completed and placed on production. platform was completed and placed on production. As of November, 1973 there were 52 development wells in the Attaka Field with 37 dual and 15 single completions for a total of 89 production strings. Within the 52 wells, a total of 173 separate reservoir zones were perforated and available for production as needed.

A cross-section of the Attaka structure (Fig. 3), reveals the lenticularity of the sands and the large gas caps which complicate the development of this field. Reservoir sand thicknesses range from 5 to 100 feet and many of the thinner reservoir zones are discontinuous through the field. Since there are over 50 sands of varying areal accumulation it would have required a prohibitive number of wells to properly develop each individual sand without the concept of multiple packer completions.

As in many new fields, particularly where there are a large number of stray sands as at Attaka, there are questionable zones that are not defined by sidewall cores or downhole logs.

These zones are usually left for secondary completions during the latter life of the field or, if the interval is large enough, a drill stem test or formation interval test is performed. At Attaka, having committed to multiple interval completions, the questionable zones were perforated and isolated from major reservoir zones by packers. Consequently, when the individual strings were put on production, there were 33 zones that each produced less than 10,000 barrels of oil before having to be shut-in because of gas, water, or sand production. Yet inspire of this, field production has been maintained at an average daily rate of 100.000 BOPD for the past two years. The success in maintaining the maximum rate can clearly be attributed to the completion techniques. As of December 1975, five and one-quarter years after the discovery of the field. one hundred million barrels of oil had been recovered from Attaka.

Reservoir Engineering Concept and Development Criteria

As the initial eight well exploratory program continued to establish the limits of the field, drill stem tests were performed to determine rock and fluid properties, productivity indices, skin damage, fluid interfaces and fault locations. Pressure build-up and drawdown data obtained from the major reservoir zones indicated that these zones could sustain daily producing rate of 1000 to 3000 BOPD and would adequately producing rate of 1000 to 3000 BOPD and would adequately drain a radial area of 1250 feet. This information was then utilized for determination of the optimum well spacing and locations.

DST results also provided data for projecting eventual production rates. It was noted during several DST's that a production rates. It was noted during several DST's that a producing rate in excess of 100 BOPD per foot of perforations producing rate in excess of 100 BOPD per foot of perforations resulted in some sand production. Since it was felt that sand control completions would reduce the productivity of the wells, a value of 75 BOPD per foot of perforations was established as the maximum producing rate. This has proved to be satisfactory except when the wells began cutting water. In certain instances when water production was first detected, the producing rate was restricted to 50 BOPD or less per foot of perforations and sand production frequently decreased or was completely eliminated. However, some zones produced sand even during the period of waterfree production produced sand even during the period of waterfree production and in such cases the sand producing zones have been shut-in and other zones opened to maintain an active tubing string.

The horizontal and vertical permeability of the loosely consolidated sands is virtually equivalent. In almost every case where gas-oil contacts are present in the wellbore or within a few feet of it, coning/fingering of gas has occurred when the producing rate has exceeded 50 BOPD per foot or perforated interval. However, by selectively opening and closing perforated interval. However, by selectively opening and closing sleeves, the field producing gas-oil ratio has actually decreased with time (Fig. 4). Producing intervals that increased to high gas-oil ratios have been shut-in and successfully allowed to re-saturate to avoid energy wastage while the tubing string was kept on production by opening alternate zones with wireline shifting tools. This flexibility has not only provided the opportunity to maintain maximum production. but has also enabled the reservoir engineers to closely monitor production and pressure decline so that proper reservoir production and pressure decline so that proper reservoir management could be practised, resulting in the maximum recover), of oil and gas.