Nine (9) wells have been successfully drilled, cemented and fracture stimulated in the tight gas sands of four (4) separate fields on the Kenai Peninsula, Alaska utilizing an industry unique Casing-Conveyed Perforating System (CCPS). For this nine (9) well program, 124 CCPS modules have been run, cemented in place, detonated and fracture stimulated. Of the nine (9) wells the initial five (5) wells were stimulated with an oil-based fluid while the most recent four (4) have utilized a water-based system. While the project has been an overall success, the drilling and completion team continues to utilize new and innovative technologies to optimize well performance and economics.
The normally-pressured middle and lower Beluga sands in the Kenai Gas (KG) and Beaver Creek (BC) areas exhibit significant vertical sections frequently exceeding 1,700 ft. The vertical pay quality is quite variable and consists of stacked fluvial sandstones 5 ft to 30 ft thick. The mineralogical composition of the sands is complex including a high percentage of quartz, clays, volcanics, coals, and fines with permeability ranging from 0.01 to 3 millidarcies. The sandstone packages are bounded by discontinuous shale, siltstone, and coal beds and present a challenging fracture stimulation environment. Produced gas is lean with a specific gravity of 0.56 with no condensate.
As mentioned above one of the most robust changes to the project has been a shift from a crosslinked oil-based (diesel) fracturing fluid to a "new-generation" aqueous based guar-borate system. This step change was made at the conclusion of extensive laboratory studies on core sections and has provided significant improvement with HSE, completion operations, well performance and ROI.
This case history paper reviews the revolutionary casing-conveyed perforating system, provides an overview of the nine (9) wells completed to date and describes the laboratory test procedures and results used to validate the use of a water-based fracturing fluid. Project cost savings are also discussed pertaining to the Total Cost of Service (TCS) differences between hydrocarbon and water-based fracturing fluids in a cold weather environment.
Introduction
From 1995 to 1998, a multidisciplinary team1 undertook an exhaustive reservoir characterization study of the Beluga formation in the Kenai Gas Field in an effort to improve well performance. During this study, it became apparent that conventional completion techniques were not optimally developing the Beluga Sand resource. Conventional completion approaches and a finite resource base resulted in a "high-grading" of the best sands in a well for stimulation typically restricting coverage to 100 ft - 150 ft net. Selective perforating strategies including limited entry techniques proved to be ineffective leaving many of the lower-quality sands unstimulated. This by-passed pay was identified as a potential 70 BCF recoverable target so the team was challenged to develop the resource.
Working from the reservoir characterization platform, the team considered a variety of techniques for improving recovery and economics from the Beluga sands before settling on the CCPS. The CCPS was developed specifically for Alaska and has subsequently been employed on nine (9) wells across several fields. To date CCPS performance has been excellent and well production robust with well performance at or above anticipated production levels. As of the writing of this paper additional CCPS wells are being planned and drilled.
