Summary This paper discusses a novel approach to well stimulation with anhydrous methanol-based fracturing-fluid that significantly reduces hazards to personnel and equipment during the fracturing process. Research is presented on the various chemical and engineering process technologies used to develop and evaluate continuously mixed anhydrous methanol fracturing-fluid performance. Field case histories are also discussed. Introduction Since the development of hydraulic fracturing technology as a well completion technique hazardous fluids frequently have been used. These fluids include refined oils, formation condensates, crude oils, acids, alcohols, and a variety of other chemicals and additives. Batch mixing is a common technique used to formulate fluids for fracturing applications. The fluid viscosity is adjusted to the desired level by circulating the base fluid through blending equipment while adding the polymeric gelling agents, buffers, and other chemicals. The fluid must circulate through the equipment many times for the fluid to develop the desired viscosity. When hazardous materials are handled in a multiple-circulation process, the potential for accidents is high. Technological advances in recent years have provided sophisticated fracturing-fluid systems and field equipment, along with microprocessor systems that monitor and control the pumping treatment. These advances have been implemented without compromising the efficiency of the total operation. In many cases, the overall system performance improved significantly. For example, the development of oil-slurried polymer concentrates and polymer hydration units led to the widespread application of continuous-mix processes to mix fracturing fluids. The damage characteristics of any fracturing-fluid system are of paramount importance to successful reservoir stimulation. Formations that have low bottomhole pressure or contain significant concentrations of water-sensitive clays are typically candidates for stimulation with non-water-based fracturing fluids. Problems with clay swelling and migration commonly are encountered in formations containing significant amounts of smectite and illite-type minerals. The degree of formation sensitivity depends on the concentration and type of clay components, clay or mixed clay orientation in the pore channel, and the ion balance between connate water and clay minerals. In low-permeability formations, capillary forces can have a significant effect on production rate and total hydrocarbon recovery. Capillary forces increase proportionally with the surface tension of the formation fluid. When the capillary forces exceed the formation-fluid driving force, a water block may occur. The use of methanol has long been recognized as an effective technique to remove formation water blockage. The miscibility of methanol with formation fluids reduces surface tension, which promotes removal of the water block and enhances fluid recovery.

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.

Introduction Highly viscous fracturing fluids that could be pumped at relatively high rates with acceptable friction pressure were first introduced 18 years ago. This viscous fluids were oil-water dispersions that created some problems because they required special mixing and pumping techniques. The fluids did, however, prove their value by creating wide, deeply penetrating fractures and by carrying high concentrations of propping agents. Since then, other high viscosity fluids have been introduced and their properties and effectiveness reported. Such fluids now properties and effectiveness reported. Such fluids now are used commonly in all areas. Because there is some variation in fluid requirements of different areas and formations, several types of fluids have evolved. All can be classed as viscous fracturing fluids. While these fluids have been used successfully, most have the same primary disadvantage: they must be batched mixed before use. Batch mixing requires that all water gelling agents be premixed in fracturing tanks before pumping. Often this premixed in fracturing tanks before pumping. Often this leads to additional rig-time expense for the operator and additional rig-time expense for the operator and additional equipment time and man hours for the service company. Also, if the procedure is not completed as planned, there can be considerable expense in preparation planned, there can be considerable expense in preparation of fluid that is not used. These expenses can become prohibitively high on large jobs, such as the prohibitively high on large jobs, such as the "massive-fracturing" type treatment. To overcome the disadvantages of batch mixing, specially prepared materials for gelling water have been developed that can be mixed continuously as the fluid is pumped down hole. These materials, first prepared from guar gum polymers, have been in use for 3 years and have proved polymers, have been in use for 3 years and have proved highly successful. More recently, lower residue guar derivatives have been used successfully. Cross-Linked Guar Gels Very high viscosities can be achieved by cross-linking the guar gels. However, preparation of cross-linked guar gels at the well location on a large volume basis has been troublesome and time consuming in the past because of the required batch-mixing technique. That is, the guar gelling agent and cross-linker are premixed in the fracturing water. Adjustments of the fluid's pH are often necessary and present problems in achieving a uniform pH in large fracturing tanks. The guar gelling agent hydrates and produces a high-viscosity solution. JPT P. 119

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