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Key coalbed methane reservoir properties can be determined using a logical history matching analysis procedure that incorporates laboratory, geologic and production data.Methane and water production data were history matched using a dualporosity, two-phase finite difference reservoir simulator modified to account for the storage and flow mechanisms unique to coal. Two field examples demonstrate the results and show the applicability of reservoir modeling to assessing the effectiveness of stimulation and predicting well performance.

Unconventional gas resources, defined as low- permeability sandstone, coal seam and naturally- fractured shale gas reservoirs, represent a huge potential resource for future natural gas supply in Australia and around the world. Because low individual well-production rates are often the norm, unconventional reservoir development may involve the drilling of hundreds of wells to make the economics attractive. Thus, careful planning, sound development strategies and cost control are critical for project success.Virtually all unconventional gas resources must be stimulated to be economic; stimulation costs are often the most significant amount of the total well expenditure. Thus, a cost-effective method for reservoir characterisation and fracture treatment optimisation is required. Because of marginal economics, techniques used to analyse the process and results are often oversimplified; this can lead to confusing or inadequate descriptions of the complex behavior of a hydraulically-fractured, low- permeability reservoir and in some cases bad development decisions. Detailed data collection programs and fracture treatment optimisation strategies are essential to adequately address the technical issues involved in unconventional reservoir development.Besides the technical challenges associated with unconventional gas development, good forethought is necessary as to the planning and execution of the overall project. The development scenarios for coal seam and low-permeability sandstone gas resources are highly statistical and succeed or fail based on the average performance of the group of wells within the project. Following proven guidelines and methods during development while integrating key technologies into the planning and optimisation process are essential for success in unconventional reservoir development.

This paper presents the results of a comprehensive reservoir evaluation of the New Albany shale reservoir in northern Kentucky and southern Indiana and Illinois. Although initially compared with the Antrim shale in the Michigan basin, the New Albany shale has been found to have very different production characteristics than the Antrim. This paper presents the results of a comprehensive study performed on behalf of the New Albany Shale Producibility Consortium (NASPC). The objectives of this study were to determine the controls on production characteristics of wells in the New Albany shale, understand well reserves, and ascertain the potential for future development in the play. The reservoir evaluation included all available geologic, formation evaluation, production, and reservoir data from multiple fields within the play. During this study, core testing was conducted to develop baseline properties required for reservoir evaluation. Study results indicated that fracture characteristics within the play are the key driver for well production characteristics and reserves. In addition, we found that matrix gas porosity, bulk permeability, methane adsorption characteristics, and net pay thickness also differentiate the New Albany shale reservoir from the Antrim. The results also indicated that horizontal wells may have the potential to improve productivity and reserves within the play by specifically targeting the characteristics of the fracture pattern within the reservoir. The results of this paper may be useful to producers in fractured shale plays who wish to improve their understanding of flow characteristics and well performance. The work presented in this paper is important because it increases the knowledge base of shale reservoir properties and characteristics and because it describes an approach that can be used to characterize shale reservoirs. Background The New Albany shale is an organic-rich shale located over a large area in southern Indiana and Illinois and in northern Kentucky (see Fig. 1). On average, the shale appears at 500 to 2,000 ft depth.1,2 A representative well log from a producing well in the play is shown in Fig. 2. The gross thickness of the organic New Albany shale ranges from about 100 to 150 ft. The shale is generally broken into four stratigraphic intervals as labeled in Fig. 2. These are the Clegg Creek, Camp Run/Morgan Trail, Selmier, and Blocher intervals from top to bottom. New Albany shale is known to be a productive gas reservoir, with some wells producing for many years. By the mid 1990s, there were 200 to 300 producing wells targeting the shale interval. There were several large, multiwell producing fields within the basin. Most of these fields were developed utilizing vertical wells, and fracture treatments were used to access and stimulate the New Albany shale interval. Gas production from wells drilled in the New Albany shale was found to be generally less than operators expected based on experiences in developing producing wells in the Antrim shale in northern Michigan. Production in the New Albany shale ranged, generally, from 30 to 100 Mscf/D per well. Water production from wells in the play has proved to be highly variable, with some wells making very little water and other wells making more than 1,000 B/D of water. Much of the mid 1990's interest in the New Albany shale was generated by operators wishing to transfer expertise gained in the Antrim shale to the New Albany shale. Projects consisted both of expansion of existing fields within the play and exploration projects in new development areas. At that time, however, there were no comprehensive reservoir studies done on the New Albany shale. Operators generally assumed that the characteristics of the shale would be similar to those of the Antrim.

Summary Pressure communication is commonly observed in fractured horizontal shale wells, particularly at early times when wells are placed on production. In this paper we present a new technique, based on the diffusion exponent from the power-law model, to quantify connectivity in multistage-hydraulic-fractured wells with complex fracture networks. In addition to explaining the theory and analysis techniques, we present examples using measured bottomhole pressure (BHP) from the Permian Basin Wolfcamp Shale that illustrate the utility of this technique to better understand the relationship between completion size, well spacing, and well performance. Using the concept of anomalous diffusion, Chen and Raghavan (2015) developed a 1D, fractional-order, transient diffusion equation to model fluid flow in complex geological media. They showed that anomalous diffusion, which can be caused by heterogeneities in the matrix or the fracture system, exhibits a power-law behavior. In addition to Chen and Raghavan (2015), Acuña (2016) demonstrated that variations in matrix block sizes, fracture conductivity, and drainage shape also exhibit power-law behavior. While the approach from these two studies is somewhat different, they each demonstrated that a generalized power-law model is often more appropriate than traditional linear- or radial-flow pressure-transient analysis techniques for unconventional shale reservoirs. Further, each work shows that the power-law response can be related to some form of heterogeneity in the drainage volume. While traditional techniques for estimating well interference have been previously developed and applied in conventional reservoirs, in this paper we focus on quantifying the magnitude of pressure interference (MPI) in unconventional reservoirs, which commonly demonstrate a generalized, power-law pressure response that is different from radial or linear flow. The examples presented in this paper are for wells from the Permian Basin Wolfcamp Shale. Under the framework of power-law behavior, our technique involves plotting pressure-interference-test (PIT) data in terms of the Chow pressure group (CPG), which enables us to define an indicator of connectivity reflecting temporal and spatial effects. On each test, we derive a diffusion exponent reflective of the MPI. We will show among other things that multiple PITs over time often indicate degrading connectivity between wells. From PIT analyses in Permian Basin Wolfcamp Shale, we were able to establish a relationship between MPI and well spacing. The first example demonstrates analyses of PITs between wells during the production phase and also shows how connectivity between wells diminishes over time. A second example applies the same analysis techniques to quantify interwell connectivity during the post-stimulation phase by analyzing a pressure falloff (PFO) after communication with other wells. A third example illustrates an application of desuperposition to remove the effect of a power-law pressure trend (PT) on interference tests. Techniques to analyze PITs assuming radial or linear flow have been previously developed; however, Raghavan and Chen (2018) showed that apparent radial or linear flow could exist under anomalous diffusion for heterogeneous reservoirs. In this work, we present a technique for analyzing power-law PIT data, which is typical of most horizontally fractured shale wells. This model is a unique approach to understanding flow behavior, quantifying well interference, and analyzing and predicting well performance in unconventional reservoirs. Our examples, which are based on high-quality BHP gauge data, show how this technique could shorten the cycle time for operators to determine the well spacing for a given completion design.