This paper provides the first technical review of a casing-conveyed perforating technique to fracture stimulate multiple sands in a single wellbore. This is an alternate well completion methodology to improve life-of-well economics. Two wells in Kenai, Alaska were recently completed using this system. The system consists of perforating guns mounted external to the casing and integral valves in the casing for zonal isolation. All equipment is remotely actuated without wellbore intervention. The first well was completed with 15 perforating modules and the second with 12 modules, each placed over a 1,700' (520M) gross interval. This case history recounts the installation of these completions and their subsequent perforation and fracture stimulation. Both completions are considered technical and economic successes. The casing-conveyed perforating technique was chosen for these Beluga Sand wells in an effort to improve life-of-well economics and total hydrocarbon recovery. An exhaustive characterization study of this multiple-pay environment recognized that conventional completion techniques were not adequately developing the resource. Low-quality Beluga sand bodies represent a large potential target of reserves, but the economics of conventional completion techniques never allowed this potential resource to be stimulated and properly evaluated. Use of this new completion technique meant that all pay sands, even those low-quality sands that had conventionally been ignored, could now be effectively and economically stimulated. Minifrac data, tracers, and production logs are used to evaluate the productive potential of these low-quality Beluga Sands. Introduction From 1995 to 1998, geoscientists, petrologists, and reservoir engineers undertook an exhaustive reservoir characterization study of the Beluga formation in the Kenai Gas Field. The middle and lower Beluga sands in the Kenai Gas Field are a normally-pressured 1,700' (520M) section characterized by stacked pay with highly variable pay quality. These fluvial sandstones are 5 to 30 foot (1.5M – 9M) thick. Permeability ranges from 0.01 to 3 millidarcies. Mineralogy is complex, including a high percentage of clays, volcanics, coals, and fines as described in Table 1. The framework grains for the Beluga sandstones are metamorphic rock fragments. The sandstones are bounded by discontinuous shale, siltstone, and coal beds. Formation gas is very lean (specific gravity = 0.56) with no condensate, and formation waters contain approximately 5,000 mg/l total dissolved solids. Recovery from the middle and lower Beluga formation in the Kenai Gas Field through 2001 is 51.6 BCF with estimated 260 BCF OGIP. During this reservoir characterization study, it became apparent that conventional completion techniques were not optimally developing the Beluga Sand resource. One problem with a conventional approach is "cherry picking" the best sands in a well for stimulation, which leaves a large percentage of pay unstimulated. Unstimulated sands contribute little to a well's productivity. Attempts to stimulate a higher percentage of pay dramatically increase the development cost, especially in an operating environment with limited services and infrastructure. Worse perhaps was that conventional completion techniques prohibited evaluation of low-quality Beluga sands to determine whether they could be commercially developed and added to the reserve base. These low-quality sands in the Kenai Gas Field were identified as a potential 70 BCF recoverable target if they could be commercially developed.

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.

SPE Members Abstract The Midway Sunset Field is the 2nd largest oil producing field in the state of California. Current production is approximately 155,000 barrels of oil per day from 9,200 wells. Due to variable productivity exhibited by wells in this productivity exhibited by wells in this field, an extensive study was conducted to determine potential production impairment mechanisms. This study was accomplished by analyzing cores, produced fluids and the organic deposition found in and around the slots of liners pulled from two wells. The reduced productivity exhibited by these wells was determined to be due primarily to the deposition of organic and inorganic components in the liner slots. This deposition can be associated with the asphaltic properties of the crude, the unconsolidated nature of the formations and the use of Thermal Enhanced Oil Recovery techniques. Quantitative and qualitative studies were performed to evaluate the damage and generate an operationally feasible and cost effective treatment. This investigation resulted in the design of a unique treatment and placement technique. Production response is presented from 35 Production response is presented from 35 wells included in this ongoing stimulation program. Candidate selection criteria and program. Candidate selection criteria and related stimulation performance are also discussed. Introduction An extensive stimulation program was implemented on two properties in the Midway-Sunset (MWSS) field. This program consisted of 37 stimulation treatments performed on 35 wells over a 2 year period. performed on 35 wells over a 2 year period. The development and implementation of the stimulation treatment utilized is described in detail in a previously published paper. This subsequent paper presents a summarized review of the ongoing stimulation program along with additional analyses quantifying the nature of the organic and inorganic fractions of the damaging deposits present in the wellbores. The first 18 wells of this program were Potter completions. Based on favorable production response from the initial 18 Potter well treatments, the program was expanded to Tulare Zone program was expanded to Tulare Zone completions. The production data from all 35 wells treated is presented along with critical properties of the Tulare and Potter formations. FIELD HISTORY The subject properties are located in the Midway-Sunset Field which lies in the southwestern portion of the San Joaquin Basin, Kern County, California. The field spans more than 50,000 acres and extends some 25 miles from the town of McKittrick southeasterly along the Temblor Range foothills to the town of Maricopa (Figure 1). Surface elevations range from 500 ft. to 1800 ft. above sea level with the productive interval occurring from just below the surface to depths below 2000 ft. P. 523

No abstract

Management of a robust completion approach, utilizing state-of-the-art technologies, has been successfully used to stimulate multiple pay tight gas sand intervals in an environmentally sensitive area near Kenai, Alaska. Management of several unique completion techniques has demonstrated exceptional effectiveness. Previous stimulation attempts were not successful in developing the Beluga sand resource to an economic level; therefore, a comprehensive study of all processes by reservoir, drilling, completion, and service company engineers was initiated to determine the best techniques to improve recovery and financial delivery. Engineering and laboratory studies were conducted to develop a complete understanding of the Beluga sandstone reservoir composition; mechanical and chemical properties were analyzed after which an extensive project was undertaken to develop a fit-for-purpose stimulation fluid. For the well completions, a novel Casing Conveyed Perforating System (CCPS), which has revolutionized multi-zone fracturing operations, was utilized. The CCPS facilitates pinpoint stimulation of multiple pay intervals in a relatively short period of time and also improves stimulation quality, hydrocarbon recovery and life-of-well economics. Recycling of the hydrocarbon-based stimulation fluid provided an additional project enhancement. The recycling process provides a stimulation fluid with excellent rheological properties. Management of the fluid recycling process also reduces the total volume of base hydrocarbon transported and stored in environmentally sensitive areas like those in Alaska. Recycling also minimizes the equipment footprint and minimizes overall completion cost. Wells completed using these unique reservoir evaluations, CCPS, and stimulation fluid recycling techniques have been considered technical and economic successes. The Beluga Sands The middle and lower Beluga sands in the Kenai Gas Field are a normally pressured 1,700 ft. section characterized by stacked pay with highly variable pay quality. These fluvial mineralogically complex sandstones are typically 5 ft. to 30 ft. thick and bounded by discontinuous shale, siltstone, and coal beds. Formation gas is very lean (specific gravity = 0.56) with no condensate, and formation waters contain approximately 5,000 mg/l total dissolved solids. Recovery from the middle and lower Beluga formation in the Kenai Gas Field through 2001 is 51.6 BCF with estimated 260 BCF OGIP.