J.P. Spivey* and M.E. Semmelbeck* Abstract A procedure is presented which allows forecasting long range performance of dewatered coal and fractured gas shale reservoirs having nonlinear adsorption isotherms, using constant pressure solutions to the flow equation for slightly compressible liquids. A correlation is presented to show the range of applicability of this procedure. Introduction Production decline curves are routinely used by engineers to predict the future performance of oil and gas wells. Because the results of decline curve predictions are used for calculating asset value and estimating future revenue, they are one of the most important tools reservoir engineers use. There are numerous variations on the basic exponential or hyperbolic decline analysis method. Fetkovitch and others have extended the decline curve analysis method to handle gas wells properly and to be able to estimate reservoir properties from the analysis of these data. However, there has been considerable drilling activity in the last 10 years into unconventional reservoirs whose wells do not follow the traditional production decline characteristic shapes. Among these problem reservoirs are coalbed methane and fractured shale reservoirs. Two factors complicate the prediction of future gas production rates in many coalbed methane and fractured shale reservoirs such as the Devonian Shale of the Appalachian Basin, the Antrim Shale of Michigan and the New Albany Shale in Indiana. The first factor common in Antrim and New Albany reservoirs is high initial water saturation and essentially zero gas flow rate at the beginning of production. The second factor common to all fractured gas shales is desorption of gas from organic material within the reservoir rock. Both of these factors can result in well behavior that is not properly predicted by conventional decline curve methods. Because of the complex production behavior of coalbed methane and fractured gas shale wells, the best way to predict performance is to use a numerical reservoir simulator which accounts for all of the mechanisms occurring during production. However, use of reservoir simulation may not be practical for all situations, particularly when many wells must be analyzed rapidly or when reservoir simulation is not available. This paper presents a rapid analytical solution that can account for production from reservoirs undergoing desorption. One extension of this method over others presented in the literature is that it accounts for nonlinear Langmuir sorption isotherms. P. 359

The productivity of the wells in a moderately rich gas condensate reservoir was observed to initially decrease rapidly and then increase as the reservoir was depleted. All wells in the field showed the same response. Compositional simulation explained the reasons for these productivity changes. During early production, a ring of condensate rapidly formed around each wellbore when the near-wellbore pressures decreased below the dew point pressure of the reservoir gas. The saturation of condensate in this ring was considerably higher than the maximum condensate predicted by the PVT laboratory work due to relative permeability effects. This high condensate saturation in the ring severely reduced the effective permeability to gas, thereby reducing gas productivity. After pressure throughout the reservoir decreased below the dew point condensate formed throughout the reservoir, thus the gas flowing into the ring became leaner causing the condensate saturation in the ring to decrease. This increased the effective permeability of the gas. This caused the gas productivity to increase as was observed in the field. There were also changes in gas and condensate compositions in the reservoir which affected viscosities and densities of the fluids. These effects also impacted gas productivity. This work is another step forward in our understanding of the dynamics of condensate buildup around wellbores in gas condensate fields.

Devonian shales and other unconventional resources can be highly fractured and may have significant amounts of gas stored by adsorption. Conventional experiments are not well suited for characterizing the properties important for describing gas storage and transport in these media. Here, X‐ray computed tomography scanning is used to determine gas storage in dynamic gas flow experiments on Devonian shale samples. Several important properties are obtained from these experiments, including fracture widths, adsorption isotherms, and matrix porosities and permeabilities.

SPE Members Introduction Evaluation of the need for infill drilling in complex, low-Permeability, gas reservoirs requires the application of advanced technology. Use of typical engineering tools such as conventional decline curve analysis, conventional pressure transient analysis, and single layer reservoir descriptions often create inaccurate results and misleading conclusions. Despite the accuracy of advanced analysis techniques, these techniques are typically not performed on a well-by-well basis in field-wide studies because the cost cannot be justified. As a result, accurate conclusions, valid for all areas of a field, are not obtained. In this paper we present a practical means of applying advanced analysis techniques to an entire field. We describe a powerful statistical method for dividing the reservoir into areas of like productive behavior. This method provides an unbiased means of comparing well performance, selecting areas for advanced analysis, and defining the areal locations where specific conclusions apply. Emphasis is placed on incorporating a sound geological and petrophysical description, and evaluating the consistency of reservoir descriptions developed through independent geological and reservoir engineering techniques. This analysis technique was used to evaluate the infill drilling potential of the Carthage (Cotton Valley) field in east Texas. The Carthage field, discovered in 1968, is a thick, layered, low-permeability gas reservoir underlying 250,000 acres in Panola County, Texas. See Fig. 1. At the time of this study, there were approximately 900 wells producing 400 million cubic feet and 300 barrels of condensate per day. The Carthage Cotton Valley sand has been classified as "tight gas" by the FERC. Prior to this study, there were three periods of intense drilling activity corresponding to authorizations of 640-, 320-, and 160-acre drilling densities. Carthage is currently experiencing a fourth active drilling period, in which numerous wells are being drilled on 80-acre spacing in selected areas of the field. GEOLOGY The geological study provided a basis for the understanding of field and well performance. Because the objective of this study was to evaluate current well performance and extrapolate our analysis to infill locations, it was critical to understand the internal structure of the reservoir and those factors which control thickness, permeability, porosity and continuity within the reservoir. The geologic study concluded that the depositional environment and subsequent diagenesis resulted in extensive compartmentalization throughout the field. While some intervals could be expected to be more continuous than others, permeability barriers and baffles exist throughout the reservoir. Sand packages which can be correlated across significant distances within the field are comprised of thin sand/shale sequences and very fine laminations which are impossible to detect on conventional logs. Severe heterogeneity is apparent both vertically and laterally. P. 35^

SPE Members Introduction Hydraulic fracturing has been used to accelerate removal of methane from coal seams ahead of underground mines. Originally, all of the gas that was produced was flared or vented. Over the past decade, however, there has been a growing past decade, however, there has been a growing awareness of the vast potential for recovery of methane gas from coal seams. This awareness is leading to the commercial exploration and development of coalbed methane reservoirs in many areas of the U.S. Coalbed methane production is viewed as a new and significant energy source. Associated methane gas from coal is now the primary source of natural gas for the state of Alabama and is rapidly becoming a major source of natural gas in the San Juan Basin of New Mexico and Colorado. The natural gas industry is still learnin how to complete wells and produce gas from coal-seam reservoirs. Compared to our knowledge of techniques for the completion and production of sandstone and limestone reservoirs, our knowledge in coal-seam reservoirs is minimal, at best. The success achieved in producing gas from shallow coal has encouraged some operators to explore for gas trapped in deep coal seams that will never be mined. One area of significant activity is the San Juan Basin. To optimize recovery from most of the wells drilled into deep coal seams, hydraulic fracturing treatments are required. Experience has shown that the design and execution of fracture treatments in coal seams is not straightforward. High injection pressures, complex fracture systems, screenouts and the production of proppant and coal production of proppant and coal fines after the treatment are typical problems facing the operator. The mechanical properties of coal are significantly different from conventional rocks. Conventional reservoir rocks typically have a value of Young's modulus in the range of 3 to 6 million psi. It is not uncommon to see laboratory measured psi. It is not uncommon to see laboratory measured values of Young's modulus for coal in the range of 100,000 to 1,000,000 psi. The low value of Young's modulus will result in the creation of very wide hydraulic fractures. Additionally, it has been found from mineback experiments that very complex fracture systems are usually created during a hydraulic fracturing treatment. Not only are multiple vertical fractures often created, but fractures propagating in multiple directions can be quite common. It is felt that this complex hydraulic fracture behavior is due to the presence of the cleat system, the complex structure of the coal matrix, and the stratigraphy of the coal seam with respect to the surrounding sediments. GAS PRODUCING MECHANISMS The mechanism of gas production from coal is substantially different than observed from conventiona reservoirs. There is littl or no free gas present in the coal. Most of the pore space in the cleat system is water saturated. Even though some free gas may exist in the cleat system, most of the gas is adsorbed on the surface of the coal. To produce this gas, the pressure in the cleat system must be reduced to cause the gas to desorb from the surface of the coal to the cleat system and diffuse through the coal matrix. Normally, significant volumes of water must be produced in order to lower the pressure in the produced in order to lower the pressure in the cleat system so that gas desorbtion can begin. Because gas desorption is the primary source of production, the gas flow rate from a coal seam may production, the gas flow rate from a coal seam may increase with time. P. 43