Solutions for Better Production in Tight Gas Reservoirs Through Hydraulic Fracturing

Abstract

Abstract The challenge to make best producers for the least investment in tight gas reservoirs has always been with the oil and gas industry since production in many tight gas reservoirs is oftentimes marginal, at best. This paper presents solutions for better production in tight gas reservoirs through hydraulic fracturing. Properly engineered hydraulic fracture treatments are enablers to achieve overall economies of scale with development of tight gas reservoirs. These treatments are conducted to bypass completion damage and stimulate production from low permeability reservoirs. They are designed using simulators with a range of capabilities in an effort to maximize the economic benefit of the treatment, effective fracture length, and number of zones producing, fracture conductivity, acceleration of recovery, addition of reserves, and minimize job failures and treatment costs. To accomplish these goals, substantial amount of information is required to describe reservoir flow capacity and provide the data needed to predict treatment pressure response as well as fracture geometry and conductivity. These data will determine the optimum size of the treatment, the maximum proppant concentration that can be pumped, and the expected production response to the stimulation. When sufficient input data are available to characterize the reservoir, the fracture geometry can be accurately modeled with a capable simulator, the treatment goals listed above can be realized and an optimum design can be reached. The design process, including selection of proppants and fluids, pumping schedule, injected proppant concentrations, total job size, pump rate, and other parameters requires an idea of the desired outcome of the job: required fracture length, possible pack concentration and clean-up time. Critical measurements from testing of actual cores has allowed to sift through the chaff to find those "gems" in hydraulic fracturing that materially improve the completion efficiency in tight gas reservoirs. Introduction A definition of tight gas reservoir is "a reservoir that cannot be produced at economic flow rates or recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal well bore or multilateral well bores."4 The major unconventional gas reservoir types include tight reservoirs, CBM, shales, and hydrates. Tight reservoirs are most important in terms of production (15.6 Bcf/D in U.S., 4 Bcf/D in Canada representing some 25% of Canadian Production)1. To some degree, there has always been production from unconventional reservoirs in virtually all North American basins in the United States such as Rocky Mountains, South and East TX, north LA, Mid-continent, Appalachia, Jonah/Pinedale, Natural Buttes, Wilcox Lobo, Cotton Valley/Travis Peak, and Clinton/Medina.