Co-Production to Overcome Water Influx in Alaskan Reservoir
- Ronald Yeager (University of Alaska Fairbanks) | Shirish Patil (King Fahd University of Petroleum and Minerals) | Samson Ning (Reservoir Experts, LLC) | Luke Saugier (Hilcorp, LLC) | Daniel Taylor (Hilcorp, LLC) | Abhijit Dandekar (University of Alaska Fairbanks) | Santanu Khataniar (University of Alaska Fairbanks)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional Meeting, 23-26 April, San Jose, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- mobile gas-water contact, alaska, water influx, co-production, gas on water reservoir
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The Sterling B4 sands is a reservoir underlain by an aquifer located on the Kenai Peninsula of Alaska. This dry gas-on-water reservoir, holding approximately 13.9 billion cubic feet (Bcf), has experienced challenges since its first development in the 1960s. The gas-water contact is very mobile and easily influenced upward by gas production. All four wells, largely producing in succession of one another, have experienced excessive water production which killed gas production. Faulty drilling and completion work exacerbated the challenges associated with bringing the gas to market.
This paper summarizes an effort to model the Sterling B4 development and determine feasible alternatives for revival of the reservoir and commercialization of the produced gas. Those alternatives include infill drilling, variable production, and co-production. Co-production is a method by which gas is produced from the gas zone and water is produced from the water zone; each stream is produced independently by either mechanical means or different wells.
The only feasible alternative found in this study is co-production. Of the two co-production methods analyzed, the highest ultimate recovery includes the utilization of an existing vertical well perforating the upper portion of the reservoir for gas production and a new lower horizontal well perforating the water zone to control the gas-water contact. Modeled production schemes proved the gas-water contact may be controlled from upward mobility by maintaining a threshold pressure difference between the bottom-hole pressures of the two producing wells. Utilizing co-production in this manner yielded incremental benefit of over 2 Bcf until shut-in limits were triggered, achieving an ultimate recovery of up to 43%.
Economic analysis of the project has proved bringing the gas to market presents a significant prize able to support production and full facility operational expense despite no other revenue streams. Should other nearby formations demonstrate sufficient targets, the economic case would be enhanced and present an even greater prize.
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