We analyzed precisely located microearthquake data detected during five hydraulic fracture treatments in the Carthage gas field of east Texas. The treatments were conducted in two adjacent boreholes within interbedded sands and shales of the Upper Cotton Valley formation. The microearthquakes were induced within narrow horizontal bands that correspond to the targeted sandstone layers. Events throughout all the treatments show strike-slip faulting occurring uniformly along vertical fractures trending close to maximum horizontal stress direction. These events are consistent with the reservoir's prevalent natural fractures, known to be isolated within the sands and trending subparallel to the expected hydraulic fracture orientation. When this uniform fracture system was activated exclusively, the detected shear deformation, measured as the moment release per unit volume of fluid injected, was constant, independent of various fluid viscosities and flow rates used. Within the base of the Upper Cotton Valley formation, anomalous event counts and moment release occurred within dense clusters that delineate bends or jogs in the fracture zones. The mechanisms are also strike-slip, but the fault planes are more favorably oriented for failure. The dense clusters show location patterns diverging in time, suggesting the expulsion of fluids from compressive fault jogs. Fluid flow forced by the adjacent slip-induced loading appears to initially extend the treatments, but the loading also tends to lock up and concentrate stress at the jogs, as evident by fewer but larger events populating the structures as treatments progress. As a result, effective drainage lengths from the boreholes may be shorter than would be inferred from the seismicity extending past the jogs. These high-moment asperities are similar to dense patches of seismicity observed along creeping sections of the San Andreas fault, where they have been attributed to localized zones of strength or stress concentration, surrounded by larger regions undergoing stable, aseismic slip. This similarity, plus large moment deficits in terms of volume injected, suggests a large component of aseismic slip is induced by the Cotton Valley treatments.

Summary Ultralow-permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane-fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concepts of single-fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume (SRV) as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3D volume (stimulated reservoir volume) of the microseismic-event cloud. This paper briefly illustrates how the SRV can be estimated from microseismic-mapping data and is then related to total injected-fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that the created and the effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important, and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated-production data are then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, well spacing, and placement strategies.

In many reservoirs fracture growth may be complex due to the interaction of the hydraulic fracture with natural fractures, fissures, and other geologic heterogeneities. The decision whether to control or exploit fracture complexity has significant impact on fracture design and well performance. This paper investigates fracture treatment design issues as they relate to various degrees and types of fracture complexity (i.e., simple planar fractures, complex planar fractures, and network fracture behavior), including the effect of fracture fluid viscosity on fracture complexity, proppant distribution in complex fractures, and fracture conductivity requirements for complex fractures. The impact of reservoir properties (including permeability, stress and modulus) on treatment design is also evaluated. The paper includes general guidelines for treatment design when fracture growth is complex. This includes criteria for the application of water-fracs, hybrid fracs, and crosslinked fluids. The paper begins with an evaluation of microseismic fracture mapping data that illustrates how fracture complexity can be maximized using low viscosity fluids, which includes an example of how microseismic data can be used to estimate the permeability and spacing of secondary or network fractures. The effect of proppant distribution on gas well performance is also examined for cases when fracture growth is complex, assuming that proppant was either concentrated in a primary planar fracture or evenly distributed in a fracture network. Examples are presented that show when fracture growth is complex the average proppant concentration will likely be too low to materially impact well performance if proppant is evenly distributed in the fracture network and un-propped fracture conductivity will control gas production. This paper also extends published conductivity data for un-propped fractures and embedment predictions for partially propped fractures to lower modulus rock to provide insights into fracture design decisions. Exploiting fracture complexity may not possible when Young's modulus is 2 x 106 psi or lower due to insufficient network conductivity resulting from asperity deformation and proppant embedment. Fracture conductivity requirements are examined for a wide range of reservoir permeability and fracture complexity. Reservoir simulations illustrate that the network fracture conductivity required to maximize production is proportional to the square-root of fracture spacing, indicating that increasing fracture complexity will reduce conductivity requirements. The reservoir simulations show that fracture conductivity requirements are proportional k1/2 for small networks and k1/4 for large networks, indicating much higher conductivity requirements for low permeability reservoirs than would be predicted using classical dimensionless conductivity calculations (Fcd) where conductivity requirements are proportionate to reservoir permeability (k). The results show that when fracture growth is complex, proppant distribution will have a significant impact on network conductivity requirement and well performance. If an infinite conductivity primary fracture can be created, network fracture conductivity requirements are reduced by a factor of 10 to 100 depending on the size of the network. The decision to exploit or control fracture complexity depends on reservoir permeability, the degree of fracture complexity, and un-propped fracture conductivity. The paper also examines the effect of fluid leakoff on maximum fracture area, illustrating potential limits for fracture complexity as reservoir permeability increases. Although the expected range of un-propped fracture conductivity is controlled by Young's modulus and closure stress, in many reservoirs it can be beneficial to exploit fracture complexity when the permeability is on order 0.0001 mD by generating large fracture networks using low viscosity fluids (water-fracs). As reservoir permeability approaches 0.01 mD, fluid efficiency decreases and fracture conductivity requirements increase, fracture designs can be tailored to generate small networks with improved conductivity using medium viscosity or multiple fluids (hybrid fracs). Fracture complexity should be controlled using high viscosity fluids and fracture conductivity optimized for moderate permeability reservoirs, on order 1 mD.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents the results of integrating microseismic fracture mapping with numerical production modeling of fracture networks in the Barnett shale. Microseismic fracture mapping has shown that hydraulic fracture treatments create large-scale fracture networks in the Barnett shale 1-2 . In this paper an approach is presented, where the fracture network measured with microseismic mapping is approximated with a numerical production simulator that discretely models the network structure in both vertical and horizontal wells.The work includes a production history match of a vertical Barnett shale well, where the microseismic mapping results were directly used to approximate a fracture network in the reservoir simulator, resulting in an estimate of effective fracture network length, average fracture conductivity and effective drainage area. In addition, a parametric study for horizontal wells is presented to show how fracture network size and density, fracture conductivity, matrix permeability and gaps in the network affect well productivity. Simulations on the effect of fracture face damage along the network, the effect of non-darcy flow in the network, and tapered fracture network conductivity that decreases away from the well are also included. The numerical model was also used to simulate how a pressure buildup test would appear based on given fracture network properties, which could be a useful diagnostic to evaluate the effectiveness of the fracture network.The results of this work illustrate how different fracture network characteristics impact well performance, which is critical for improving future horizontal well completion and fracturing strategies in the Barnett shale. This could include optimizing the number of fracture stages along the lateral, length of the lateral, treatment sizes, and perforation strategies as well as enhancing fracture network conductivity and the effectiveness of re-fracture treatments. The work also shows how microseismic mapping results can be integrated with production modeling, thereby providing a tool for more realistic infill drilling and well placement studies in the Barnett shale or similar types of reservoirs.

Unconventional reservoirs such as gas shales and tight gas sands require technology-based solutions for optimum development. The successful exploitation of these reservoirs has relied on some combination of horizontal drilling, multi-stage completions, innovative fracturing, and fracture mapping to engineer economic completions. However, the requirements for economic production all hinge on the matrix permeability of these reservoirs, supplemented by the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations demonstrate that ultra-low shale permeabilities require an interconnected fracture network of moderate conductivity with a relatively small spacing between fractures to obtain reasonable recovery factors. Microseismic mapping demonstrates that such networks are achievable and the subsequent production from these reservoirs support both the modeling and the mapping. Tight gas sands, having orders of magnitude greater permeability than the gas shales, may be successfully depleted without inducing complex fracture networks, but other issues of damage and zonal coverage complicate recovery in these reservoirs. As with the shales, mapping has proved itself to be valuable in assessing the fracturing results. Introduction Unconventional reservoirs provide a significant fraction of gas production in North America and increasing amounts in some other regions of the world. Such reservoirs include tight gas sands, coalbed methane (CBM), and gas shales; in 2006 these reservoirs provided 43% of the US production of natural gas (Kuuskra 1). Because of their limited permeability, which is foremost among many other complexities, some type of stimulation process (and/or dewatering in the case of CBM) is required to engender economic recovery from wells drilled into these formations. The focus of this paper is on gas shales, with particular emphasis on how these reservoirs perform relative to tight gas sands. The important role of natural fractures in both the stimulation and production processes, the importance of conductivity in the developed fracture or fracture system, and the critical influence of the matrix permeability are investigated using both mapping and modeling results. Gas shales, such as the Barnett, Fayettville, and Woodford in North America, are relatively recent plays, but gas production from shales has occurred since the early 1900's from the Devonian shales of eastern North America and more recently from the Antrim shale and others. These shales 2 typically contain a relatively high total organic content (e.g., the Barnett has a total organic content of 4–5%) and are apparently the source rock as well as the reservoir. The gas is stored in the limited pore space of these rocks (a few per cent, including both matrix and natural fractures) and a sizable fraction of the gas in place may be adsorbed on the organic material. Matrix permeabilities of these shales are extremely difficult to measure because they are so low, but various approaches to determine their value have yielded permeabilities on the order of 1–100 nanodarcies. Clearly, economic production cannot be achieved without an enormous conductive surface area in contact with this matrix, either through existing natural fractures or the development of a fracture "network" during stimulation. Economic production would then also rely on the existence or development of sufficient conductivity within this network.