Abstract

Most of the northern Oman fields have tight carbonate reservoirs. The field under study was initially produced under natural depletion with declining reservoir pressures through vertical and horizontal wells (1990-2002), then followed by two years water flood piloting and thereafter full field line drive water flood implementation through open hole horizontal wells.

After more than 10 years of water injection, water production increase is seen in most of the wells and water cut reached an average of 65-75% in the major producing blocks. Based on current data, the ultimate recovery factor of the current water flood development from these blocks is expected to be as high as 40-45%.

In sight of the continuous increase of water production from the field and taking into account that more than 50% of the field's oil initially in place will not be recovered by the current secondary production mechanism (water flood), the block operator initiated research work on the tertiary production mechanism to maximize the oil recovery from the field. Extensive laboratory and field testing works were performed over the past five years to select the suitable and optimum IOR/EOR technique to be implemented in this tight carbonate reservoir. The process started with screening of different EOR methods and was followed by laboratory fluid behavior testing and core flooding experiments for the selected method. Out of all EOR methods, chemical EOR was screened as the most convenient and applicable method to be implemented due to the nature of both reservoir and fluid. This paper summarizes the working process which was followed to eventually select the convenient chemical starting from screening process, then laboratory work, followed by single well field testing and eventually extended injection field testing. High level results will be presented for the first three milestones and more elaborations on the extended injection field testing will be presented. Results for both field trials; the huff and puff and the extended injection are encouraging with incremental oil gains exceeding the expectation from these trials.

The extended chemical injection field trial was executed in ~ 40 acre, horizontal line drive pattern utilizing two horizontal injectors and four horizontal producers with two vertical pressure observation wells. The evaluation of injection results was based on actual daily production and injection data as well as reservoir log and core data collected before chemical injection. Comparing to water flood, initial recovery factor evaluation indicate possible improvement of up to 18% (per pore volume injected) in unit A which has more mature water flood where water cut exceeding 80% but less oil volume. Recovery improvement in unit B, a less mature water flood reservoir unit, was not remarkable. Post job analysis and review claims this due to the relatively immature water injection and thus lower water cut in this reservoir unit. Unit B is also three times thicker than unit A, which meant it received a lower chemical volume, which might have resulted in a lower recovery performance.

With limited field trials of surfactant injection in tight carbonate reservoirs in Middle East, this case study will help to enrich the literature with actual field data of continues surfactant injection in tight carbonate field.

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