A multi-well test program designed to study the gas production mechanisms of the eastern Devonian shale reservoirs was completed. Two offset wells were drilled as observation wells in Meigs County, OH. This paper presents the engineering design of the tests, data acquired, analysis techniques, and results of the analysis. The results indicated a complete anisotropic, layered reservoir system which implies directional gas flow and orientation of natural fractures. This study has provided an insight into the production behavior of reservoirs. It will aid future development of shale gas by optimizing well spacing and understanding of the gas release mechanisms of the Devonian shales.
This paper describes the use of a dual porosity radial gas flow simulator for estimating values for the key parameters controlling gas production from the Devonian shale or similar unconventional resource. Using best estimates from the literature on shale fracture and matrix properties as a starting point, the model is used to history match production decline and cumulative production data from a Devonian shale well in Meigs County, Ohio. Three sets of parameters were obtained which gave good agreement with the production data. Utilizing simulated pressures at a production data. Utilizing simulated pressures at a distance of 96 feet (29.3 m) as a third matching parameter, it was possible to distinguish between the parameter, it was possible to distinguish between the three cases and thus obtain a "more unique" match. From the results obtained it is concluded that interference data can provide additional information needed for determining the key parameters that control shale well deliverability. Introduction Devonian shale wells have produced in the Appalachian Basin for 50 to 100 years with very low but sustained productivity. In recent years there has been a large effort by government and private industry to develop and implement improved techniques for recovering a greater percentage of gas from this important resource. A part of this effort involves the development of mathematical models with predictive capability so that various alternative production schemes can be investigated and accurate forecasts of additional recovery can be made. Most Devonian shale reservoirs are believed to consist of a very tight, low porosity shale matrix with high storage capacity and low flow capacity coupled with a relatively high flow capacity natural fracture system of very low storage capacity. As pointed out by Smith et al the weight of all pointed out by Smith et al the weight of all available evidence favors the position that the shale matrix provides the major contribution of the recoverable gas. The Kucuk-Sawyer model was used in this study in an effort to approximate the key parameters controlling gas production from a particular shale well in Meigs County, Ohio. The model was used in the history mode so that observed and simulated data were plotted for immediate comparison. Parameters were plotted for immediate comparison. Parameters were adjusted manually until good agreement between observed and simulated production decline and cumulative production curves was obtained. Good matches were obtained for three sets of the following parameters:fracture porosity,fracture permeability,fracture spacing,matrix porosity, andmatrix permeability. In an attempt porosity, and (5) matrix permeability. In an attempt to obtain "more uniqueness" the simulated pressures at a distance of 96 feet (29.3 m) were compared for three "matches". It was found that, for each of the three sets, pressures were significantly different. Thus the possibility of utilizing interference data from offset wells to delineate storage and flow properties of the Devonian shale is inferred. Details properties of the Devonian shale is inferred. Details of the matching procedure and the sensitivity to the various parameters are presented. Background Warren and Root and Kazemi have presented models and techniques for analysis of naturally fractured reservoirs for the flow of compressible liquids. Kazemi et al also studied the pressure behavior of an observation well in a naturally fractured reservoir with an adjacent well produced at a constant rate. It was found that the early time response was substantially different from that of an equivalent homogeneous reservoir. Crawford et al analyzed more than twenty field-measured pressure buildup curves in a reservoir know to be naturally fractured and concluded that the Warren and Root model adequately described the buildup response and is therefore useful in determining effective (fracture system) permeability. In 1976 DeSwaan presented an analytical model for a naturally fractured reservoir which does not involve the Warren and Root parameters. P. 137
Mathematical models for predicting gas performance of Devonian gas shale reservoirs can be divided into two groups: single and dual porosity models. Further, two dual porosity models have been developed. Although the shale matrix is known to contain a large quantity of gas, it is not known what fraction can be produced economically. No conclusive evidence in support of the various model concepts is given, but the information in this paper will facilitate comparison of existing models. Area requiring further study in order to advance current modeling technology are discussed.
A series of multiple well transient tests were conducted in a Devonian shale gas field in Meigs County, Ohio. Production parameters were quantified and it was determined that the reservoir is highly anisotropic, which is a significant factor in calculating half-fracture length from pressure transient data. Three stimulation treatments, including conventional explosive shooting, nitrogen foam frac, and high energy gas frac (HEGF), were compared on the basis of overall effectiveness and performance. Based on the evaluation of results, the nitrogen foam frac provided the most improved productivity. The study provided the most improved productivity. The study provided new type curves and analytical solutions for provided new type curves and analytical solutions for the mathematical representation of naturally fractured reservoirs and confirmed that the shale reservoir in Meigs County can be modeled as a dual porosity system using pseudosteady-state gas transfer from the matrix to the fracture system. Introduction The Devonian shales in the Appalachian Basin are comprised of very low-permeability naturally fractured rock formations, and stimulation is usually needed to make wells productive. Continued testing has focused on determining the most effective and economical methods of stimulation for given reservoir characteristics. Thus, the thrust of research in the region has been concurrent in two areas:quantification of specific reservoir characteristics, anddesign of stimulations to fit given reservoir characteristics. The Multiple Well Transient Test Program, initiated in 1982, was designed to aid Program, initiated in 1982, was designed to aid the Gas Research Institute in their research efforts. The specific objectives of this study were to:Confirm reservoir properties delineated from earlier interference tests at a greater areal extent.Evaluate changes in reservoir drainage patterns due to stimulation.Test stimulation concepts in established production zones.Develop methods to evaluate well performance after stimulation. Five wells drilled into the Upper Devonian-age Huron member of the Ohio shale were used in the study. A central producing well (Well 10056) with a 25-year production history was surrounded within several hundred feet by four offset wells (Wells A, B, C, and D) as shown in Figure 1. The location of the four offset wells was particularly important in potential quantification of reservoir characteristics. potential quantification of reservoir characteristics. Well B is located along the direction of expected minimum reservoir permeability 90 feet (27 m) from the central well. Wells A and C are located along the direction of expected maximum reservoir permeability 120 and 700 feet (37 and 213 m), permeability 120 and 700 feet (37 and 213 m), respectively, from the central well. Well D is a directionally drilled well which penetrates the target horizon 880 feet (268 m) from the central well, making it a suitable well for far-field testing. Of the four offset wells, only Well C, the far-field offset in the direction of expected maximum permeability, was drilled under this project. permeability, was drilled under this project. A total of 17 pressure transient tests consisting of single well tests and multiple well interference tests were conducted. Analysis of these tests was supported by theoretical studies done at the University of Tulsa. Nitrogen foam fracture and experimental high energy gas fracture (HEGF) stimulations were performed and the results compared to the earlier explosive treatment of the central producing well. A reservoir simulator, SUGAR-MD", was producing well. A reservoir simulator, SUGAR-MD", was used to evaluate the performance of both procedures. DESCRIPTION OF WORK The drilling site for Well C was selected by plotting pressure response versus distance using plotting pressure response versus distance using information from previous testing. Calculations indicated that after 30 days the pressure response along the maximum permeability direction 700 feet (213 m) from the central well would be an estimated 40 psi (276 kPa). Such a response would be adequate for analysis, so the new well was located at a point 700 feet (213 m) along the axis of the central well and Well A. Well C was drilled through the Lower Huron member of the Ohio shale, into the underlying Hanover member of the Olentangy shale, to a total depth of 3496 feet (1066 m). P. 381
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