Abstract Gas production from the Devonian Shale is attributed to the ability to connect the natural fracture systems that occur throughout the shale. Hydraulic fracturing has long been standard practice, and is required for most shale wells to produce appreciable gas flows. Since the mid-1980's most operators have used straight nitrogen as the fracturing medium, believing residual water from foam fracturing treatments delays or reduces gas flow from the shale. Nitrogen fracturing, however, increases the difficulty of stimulating multiple zones perforated over long intervals, another aspect of successful shale well completion. Conventional fracturing treatments currently apply high pump rates (>50 MSCF/MIN) and ball sealers dropped throughout the job in an effort to maximize zonal coverage. However, post-frac production logs indicate that some perforated zones do not contribute to the flow. Coiled tubing operations provide a system with which each zone in a multi-zone completion can be isolated, treated and monitored individually. The ease of downhole relocation with coiled tubing allows several zones to be treated in a continuous operation. A broad range of frac gradients has been exhibited in every wellbore treated to date, indicating that conventional treatments will never achieve total zone coverage. While some gradients are so high they cannot be fractured even when isolated, zone coverage has improved by greater than 20% compared to conventional treatments. Early treatments indicate that coiled tubing fracturing offers a slight economic improvement over conventional treatments. Treatment costs have been comparable, while coiled tubing treatments have achieved marginally higher production rates. Results should improve, however, for at least two significant reasons: additional reserves are made available due to improved zone coverage; and job design is in the early stages of development. The importance of rate and volume are being assessed and early indications are that both will contribute to improved economics. Introduction The Devonian Shale is a naturally fractured reservoir, and ranges in depth from 2,500' to 6000' with a fracture gradient ranging between 0.4 to 0.6 psi/ft. The bottom-hole temperature ranges from 80°F to 120°F and has a reservoir pressure of 80 to 1200 psi. Prior to Nitrogen gas treatments, the shale was stimulated primarily with foam fracturing treatments. It was thought that the only method of connecting the fracture system was with proppant, however, the Devonian Shale, being a very water sensitive formation, doesn't completely clean up following a foam fracturing treatment. Nitrogen gas treatments were introduced as an alternative method that could sufficiently connect the array of natural fractures Nitrogen treatments could also allow for quicker and more efficient cleanup and reduce damage to the reservoir from fracturing fluids. The first Nitrogen treatment was performed in the mid-1980's. While the results indicated that the initial open flow was lower, the well produced in line better than the offset foam stimulated well.

Abstract When pumped at sufficient rates and pressures, gaseous nitrogen alone has been pressures, gaseous nitrogen alone has been successfully used as a fracturing fluid in the Ohio Shale Formation of the Devonian shale trend. Enhanced production results have proved that use of nitrogen, even without a propping agent, has outperformed other stimulation systems employed in this lithological area of Ohio and West Virginia. Job design and procedures for nitrogen fracturing are presented in this paper as are production results of five treatments production results of five treatments performed in the Ohio Shale Formation. performed in the Ohio Shale Formation Introduction In Washington County, Ohio, there are as many as 14 different producing zones. Encountered at depths of approximately 2,000 feet to 3,900 feet, the Ohio Shale Formation is considered to be any zone located below the Berea Formation and above the Huntersville Formation. Porosity in the Ohio Shale Formation is low, ranging from 0.1 percent to 4 percent. Overburden pressures percent to 4 percent. Overburden pressures vary from 1,600 psi to 2,700 psi. Also, permeability values range from 0.0001 md to permeability values range from 0.0001 md to 0.01 md which results in low production rates. These low rates of production occur because the low permeability of the shale limits the rate at which reservoir fluids can diffuse through the formation matrix, through natural fractures and on to the wellbore. However, extended production lives are observed as a result. The area also has a low stress ratio factor which implies a high density of natural fractures. This accounts for the large volumes of trapped oil and gas and also contributes to the porosity of the system, thus, allowing the zone to act as a reservoir. Because initial production usually declines rapidly, stimulation is required to increase or maintain rates. The rapid decline of initial production is due to the random distribution of fractures characterized by a lack of communication between fractures in the zone and between fractures and the wellbore. Such low pressure reservoirs also make clean-up operations difficult. Following conventional treatments, most wells in this area load up with fluid while flowing back and then die. Consequently, a swabbing unit is usually required to help recover treating fluids. The failure to completely recover treating fluids is often considered the cause of poor production rates. The problems inherent with conventional fracturing treatments, including lost production, additional costs of swabbing production, additional costs of swabbing operations, and possible formation damage from unrecovered fluids, forced local operators to pursue new ways to treat wells in the Ohio Shale Formation. STIMULATION HISTORY Zones such as the Ohio Shale Formation, which have high shale content and natural fractures, have long been difficult to stimulate. These formations can be characterized as virtually impermeable, low-pressure reservoirs requiring special efforts to enhance recovery of hydrocarbons. The productivity of wells drilled in this interval is dependent on the density and extent of the natural fractures within the shale matrix. The fractures in the reservoir are both the source and the seal for organic carbons. P. 189