The interest in exploitation of ultra-low permeability formations, such as the Marcellus Shale, has increased in the recent years. Shale formations require massive stimulation treatments to achieve economic production. The recent advances in horizontal drilling and multistage hydraulic fracturing have proved successful in achieving commercial production. However, the parameters that directly affect lifetime production of the wells have not been well established. The primary objective of this study is to examine the effects of basic stimulation parameters used in hydraulic fracturing of Marcellus Shale wells on production performance. Historical production data and stimulation treatment information have been collected and analyzed for a number of horizontal wells both in West Virginia and Pennsylvania. A commercial reservoir simulator which utilizes a dual porosity model and accounts for adsorbed gas was utilized for history matching and predicting the long term production performance. The impact of the stimulation parameters including number of stages, stage spacing, the volume of water used, and the volume of sand used on production performance was investigated. An understanding of the impact of each stimulation parameter to overall production of a well can be used for the optimization of stimulation treatments.

EQT Production has been an active driller in the Lower Huron Shale in the Appalachian basin for nearly 100 years and has close to 5000 producing vertical wells in Kentucky alone. In 2006, EQT began drilling horizontal wells and has drilled over 400 Lower Huron Shale and over 100 Cleveland Shale wells in Kentucky through mid-2010. EQT has experimented with various completion designs and fracture methods in order to maximize production from these wells. EQT traditionally has performed both foamed nitrogen and nitrogen gas hydraulic fracture treatments, with the selection between the two dependent on reservoir pressure data taken from vertical offset wells drilled and completed in past decades. EQT also performed 33 hybrid (ultra-high quality foam) treatments on Lower Huron wells and compared their production against the production from their offsets. EQT studied the effect that frac stage length has on well production. The method in which the open-hole packers were set was also analyzed and found to be influential in well performance. From these studies, EQT has identified ways to improve well performance for a minimal cost by altering the completion design and has implemented these design changes in their completion programs.

Abstract One of the major producing zones in the Texas panhandle is the Granite Wash. The Granite Wash play is currently focused on Wheeler and Hemphill counties on the Oklahoma border and covers more than 1,000 sq mi of tight-sand formations. The focus is less on discovery and more on cost reduction in drilling and stimulating wells. The Texas Railroad Commission in some cases has lowered spacing to 40 or 20 acres per well, which, along with steadily high gas prices, form the basis of the high rig count working in the region. Because of the lack of concise and consistent nomenclature in the Granite Wash plays of the Anadarko Basin, this case study addresses the stimulation trends the industry is using in the Wash play. The target area of this study consists of three counties located in the Texas Panhandle: Wheeler, Hemphill, and Roberts, with extensive data only within the Buffalo Wallow Field. This paper discusses the reservoir development and characteristics, current and former completion techniques, and production comparisons. The goal for this study is to determine best practices for completion procedures in the Granite Wash. Previous satabases 1 have been expanded using detail data on fracture treatments performed and production recorded from 135 wells over the given period from 2002 through early 2006. The operator and service provider are currently analyzing the data. The goals of this analysis are to (1) define basic criteria (rules of thumb) 2 for optimizing the potential for the highest initial production and 90-day cumulative production, and (2) discover correlations, if any exist. The data of interest reside in each well's specific fracture treatment data that includes the following, but is not limited to treatment rate, proppant volume, treating fluid volume, gross pay interval, net pay interval, proppant mesh size, and treating pressure. One example of the correlations obtained is: based only on rate, if the treatment is pumped at a minimum of 100 bbl/min, a good well will be achieved 66.7% of the time versus 55.2% when the treatment is pumped below 100 bbl/min. When the production criterion is 60-day cumulative production, the gap lessens: 65.6% when the treatment rate is over 100 bbl/min; 60.7% when the treatment rate is less then 100 bbl/min. Many other correlations regarding perforated interval, treatment volume, proppant mass, proppant sieve size, etc. are presented in this paper. Introduction Currently there are many questions revolving around the Granite Wash play and the "best" way to gain economic production from it. The play is expanding to cover more than six counties in Oklahoma and Texas along the Oklahoma-Texas border ( Fig. 1 ). Do we waterfrac these wells? Will low proppant concentrations and hence, low conductivities give us long-term production and adequately drain each section effectively? This paper asks and answers questions regarding fluid volumes, proppant type, mass, and concentrations, and correlates the answers to production, given a tight geographic local (the Buffalo Wallow Field), to determine a best practice to be used in the field. Geology A target reservoir in this basin, the Pennsylvanian Granite Wash, was deposited in a series of alluvial fans and fan deltas that formed rims around these structural highs that developed during the Pennsylvanian Period in response to major continental collision associated with the Ouachita Orogeny. 3 Conversely, units of early Paleozoic age (older than the Granite Wash) were deposited on a stable, shallow shelf periodically covered by epicontinental seas. Eventually erosion of the basement uplifts led to their planation and burial, which was followed by deposition of a series of Permian-age red-bed and evaporite facies. These evaporites form the top seal for the Granite Wash. As shown in Fig. 2 , a wide geographic distribution of washes exists. These Middle Pennsylvanian washes were sourced from the Amarillo uplift, distributed throughout time. There is also an evident change in "wash" composition; early washes (Morrowan) are typically chert. Atokan washes vary from chert to carbonate, Lower and Middle Cherokee washes are typically carbonate. Red Fork washes are commonly carbonate washes with granitic material found within and controlled by local drainage areas during deposition.

ABSTRACT From January, 1993 through July, 1994 Marathon Oil Company completed ten newly drilled gas wells using coiled tubing as the initial production string. This paper reviews the operational aspects of each job and summarizes the areas where improvements in equipment and technique were implemented. The use of coiled tubing allows the tubing size to be closely matched to the performance of these relatively low rate wells, minimizing the tubular costs and improving the well's ability to stay unloaded. The main areas of improvement from one job to the next involved the use of a pressurized, hydraulically operated access window, ensuring that all frac sand was cleaned out prior to landing the coiled tubing and employing a "hot cut off" system to make the final cut on the coil tubing. Lessons learned include keeping the coiled tubing size large enough to run smaller coiled tubing through it for clean out and slickline work, care in closing the BOP rams to avoid damaging the pipe and the use of wellhead equipment specifically designed for coiled tubing. This technique is especially suited to low pressure and water sensitive reservoirs where loss of fluid is of concern. An additional benefit is the cost savings from reducing the hole and casing sizes to match the reservoir potential. This completion technique is often quicker than using a conventional completion rig and jointed tubing. INTRODUCTION Marathon has used coiled tubing for initial production tubing in several wells in order to match the tubing to the well productivity, unload frac fluids as quickly as possible and to minimize cost by reducing the time the drilling rig stays on location. An additional benefit is that no fluid is lost to the formation during the completion.

Abstract After redesigning stimulation treatments to include hydraulic fractures with an epoxy-coated sand final stage, Texaco has achieved a two-fold increase in initial oil production from its Illinois Basin wells completed in the Salem Limestone. Previous treatments conducted in Salem Lime wells included gelled acid with rock salt diverter, and foamed acid jobs. Initial production increases were favorable, but production declined rapidly. Acid-etch tests on Salem Lime cores showed poor conductivity gains. Twenty-seven subsequent sand fracture treatments pumped with an epoxy-coated proppant in the last stage resulted in initial production averaging 60 BOPD per well. The previous treatments averaged an initial production of 24 BOPD per well. The epoxy-coated final stage served to lock proppant in place after wells were placed on production. This paper presents job designs and case histories showing the benefits of fracture-stimulating the Salem Limestone for production enhancement. Background The Salem Field, in Marion County, Illinois, was discovered by Texaco in 1938. The field reached peak oil production in December, 1939, when it was producing 261,000 BOPD. The 8,800-acre field was unitized in 1950 to waterflood five pay horizons. Fig. 1 (Page 2) shows the relationship of the Salem pay zone to other formations. Peak waterflood production was 27,000 BOPD in 1961. The Salem field has produced 396 million barrels of oil since it was discovered. Infill drilling and a recompletion program in the Salem Limestone have elevated current production in the Salem Unit to 3,000 BOPD. Recompleted Salem zones stimulated by hydraulic fracturing with an epoxycoated tail-in sand have reduced the field's annual decline rate from 6.7% to zero, with a production increase of 300 BOPD. The Fig. 2 production curve (Page 2) shows production levels for the past decade.

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