Completion Optimization Provides Step Changes in Horizontal Well Performance in the Nuiqsut Formation – An Oooguruk Field (Alaska) Case History
- Andy Bond (Caelus Energy Alaska) | Rami Jasser (Caelus Energy Alaska) | Vern Johnson (Caelus Energy Alaska) | Mike Morgan (Caelus Energy Alaska) | Mike Martin (Northern Solutions) | Terry Palisch (CARBO Ceramics) | Brock Williams (Resman)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 28-30 September, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2015. Society of Petroleum Engineers
- 5 Reservoir Desciption & Dynamics, 5.6 Formation Evaluation & Management, 2.2 Completion Installation and Operations, 2 Well completion, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.5.1 Fracture design and containment, 4.1.2 Separation and Treating, 1.6 Drilling Operations, 4 Facilities Design, Construction and Operation, 1.6.6 Directional Drilling, 4.6 Natural Gas, 5.6.5 Tracers, 4.1 Processing Systems and Design, 2.2.2 Perforating, 5.4.2 Gas Injection Methods, 2.5 Hydraulic Fracturing, 2.4.3 Sand/Solids Control, 5.4.1 Waterflooding, 4.6 Natural Gas, 5.4 Enhanced Recovery
- Field Development Case Study, Horizontal Well Fracturing, Horizontal Well Completions
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The Oooguruk Unit is located on a man-made gravel island in the Beaufort Sea, five miles offshore the Alaskan North Slope in Harrison Bay. The field produces from the Kuparuk, Torok and Nuiqsut reservoirs. The focus of this paper is the Nuiqsut sandstone which is currently undergoing water and lean gas injection for secondary recovery. The wells are completed as 6,000 ft to 7,000 ft horizontal laterals aligned parallel with the preferred fracture orientation in a line drive waterflood pattern. Recent optimizations in mechanical diversion fracturing in these laterals have provided significant improvements in production rates including several recent wells with initial production of over 7,000 BOPD. This paper will document the completion and fracturing design evolution over several vintages of wells, as well as the use of pre-installed tracer systems to verify production uniformity and diversion success.
The reservoir ranges in thickness from 60 ft to 120 ft and is divided into several producing sand and shale intervals. The initial completion type planned for this reservoir was an 8,000 ft long undulating open hole horizontal lateral. This was quickly abandoned after the first well collapsed in a shale section. Undulated wellbores continued to be drilled for producing wells but were completed with pre-perforated pups spaced evenly throughout the liner in the horizontal section. These wells were stimulated with dynamic diversion fracturing treatments. Because of the logistical difficulties and expense in fracturing operations on a gravel island in the Beaufort Sea, two wells were also completed as multi-laterals, but resulted in productivity similar to dynamic diversion fracturing in one well and significantly less in the second well.
The initial move to undulated horizontal wellbores utilizing dynamic diversion fracturing treatments resulted in production improvements of nearly 100% over unstimulated wells. This led to the use of mechanical diversion techniques implemented in relatively flat horizontal laterals. This completion-type allowed mechanical diversion fracturing treatments utilizing over three times the low density ceramic proppant and generated wells with initial production of over 7,000 BOPD (an additional 100% increase over dynamic diversion fracturing). All future producing wells are now planned to be completed with mechanical diversion equipment. The completion optimization evolution described in this paper will be useful to completion and development engineers of other conventional reservoirs, and the learnings are already being successfully applied to another nearby Alaskan North Slope development.
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