Completion Optimization Provides Step Changes in Horizontal Well Performance in the Oooguruk Field, Alaska
- 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 Drilling & Completion
- Publication Date
- March 2017
- Document Type
- Journal Paper
- 1 - 12
- 2017.Society of Petroleum Engineers
- Fracturing, Conventional Reservoir, Horizontal Wells, Waterflood
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- 510 since 2007
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The Oooguruk Unit is on a man-made gravel island in the Beaufort Sea, five miles offshore the Alaskan North Slope (ANS) 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- 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 more than 7,000 BOPD. This paper will document the completion and fracturing-design evolution over several vintages of wells, as well as the use of preinstalled tracer systems to verify production uniformity and diversion success.
The reservoir ranges in thickness from 60 to 120 ft and is divided into several producing sand and shale intervals. The initial phase (I) of completions planned for this reservoir was to use 8,000-ft-long undulating openhole horizontal laterals. However, these were quickly abandoned after the first well collapsed in a shale section. The second phase (II) used undulating wellbores for producing wells, but were completed with preperforated pups spaced evenly throughout the uncemented liner in the horizontal section. These wells were also stimulated with dynamic-diversion fracturing treatments that used ball sealers. Because of the logistical difficulties and expense in fracturing operations on a gravel island in the Beaufort Sea, two wells were also completed during this phase as unfractured dual-laterals, but resulted in productivity similar to dynamic diversion fracturing in one well and significantly less in the second well. During these phases of increased well productivity, modifications were required to increase waterflood well injectivity, which was accomplished by implementing a system of high-pressure breakdown (HPBD) stimulations, as well as fully mechanical diversion-fracture treatments. These changes in injection-well completions will also be described in the paper.
Phase II wells resulted in production improvements of nearly 100% over the Phase I completions. This led to the third phase of development, which used mechanical-diversion techniques, implemented in relatively flat horizontal laterals. This completion type allowed mechanical-diversion fracturing treatments that placed more than three times the low-density ceramic (LDC) proppant and generated wells with initial production of more than 7,000 BOPD (an additional 100% increase over Phase II completions). 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 lessons learned are already being successfully applied to another nearby ANS development.
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