Summary
Microseismic mapping is extensively used in the Barnett Shale to map hydraulic fracture complexity associated with interactions of the stimulation with pre-existing fractures (fracs). Previous studies have indicated a fair correlation between the well performance and extent of the seismically active volume. However, in addition to this measure of the extent of the stimulated fracture network, the characteristics of this fracture network is also expected to impact the well performance. In particular, the fracture spacing is believed to be an important factor controlling the potential gas flow. In this paper, we use the density of the total seismic moment release (a robust measure of the microseism strength) as an indication of the seismic deformation that may correlate to the fracture density. The study uses a set of microseismic maps of hydraulic fracture stimulations, including cases in which the stimulated reservoir volume measured by the extent of the seismically active region poorly correlated with the well performance. Incorporating the seismic moment density to assess the fracture density with the network extent, an improved correlation with the well performance was observed.
Introduction
Microseismic mapping of hydraulic fracture stimulations has become a common technique to map the fracture growth and geometry (Warpinski et al. 2004; Fisher et al. 2002; Maxwell et al. 2002; Fisher et al. 2004; Rutledge et al. 2004; Shapiro et al. 2004; Chambers et al. 2008; Lu et al. 2008; Warpinski et al. 2005). Microseismic images provide details of the fracture azimuth, height, length, and complexity resulting from interaction with pre-existing fratures. The resulting images can be used to calibrate numerical simulations of the fracture growth, allowing more confident modeling of other stimulations in the field, and a better identification of the stimulated region that may ultimately be drained by the well.
Arguably, the Barnett Shale is the field that has had the most fracs mapped over the last several years. Microseismic mapping in the Barnett Shale has repeatedly demonstrated extreme fracture complexity resulting from interaction between the injection and a pre-existing fracture network (Fisher et al. 2002; Maxwell et al. 2002; Fisher et al. 2004; Rutledge et al. 2004; Shapiro et al. 2004; Chambers et al. 2008; Lu et al. 2008; Warpinski et al. 2005; Mayerhofer et al. 2006). Even between neighboring wells, the geometry of the stimulated fracture network shows a high degree of variability caused by localized differences in the fracture network (Fisher et al. 2002). The Barnett Shale has a low-intrinsic matrix permeability, and the permeability enhancement associated with the fracture stimulation results in permeable fracture networks sufficient for economic gas recovery in the field. Previous studies have shown a correlation between the volume of the reservoir stimulated as measured by the volume of the reservoir that emits microseisms during the stimulation, and the production ultimately realized from the well (Fisher et al. 2002; Fisher et al. 2004; Mayerhofer et al. 2006). The correlation is attributed to larger fracture networks being stimulated in wells in which a large microseismically active volume of the reservoir has been realized, resulting in more permeable fracture pathways connected to the well and therefore a higher potential for gas flow to the well. Recently, many operators in the Barnett Shale have attempted horizontal completions, which have allowed large volumes of the reservoir to be stimulated with large fracture networks. Many of these completions use perforated, cemented liners, and the microseismic images allow for indentification of improved perforation staging to maximize the stimulated reservoir volume (SRV) (Fisher et al. 2004).
Many of the Barnett Shale stimulations are water fracs in which large volumes of water are injected at a high rate (Mayerhofer et al. 1997). One possible mechanism for the success of waterfracs is that increased fluid pressure in natural fractures induced shear failure, resulting in fracture dilation associated with mismatched surfaces on opposite sides of the fracture. Within this conceptual framework, the microseismic events correspond to the actual fracture movement. The earlier investigations of the SRV measured the total volume of the microseismically active region. However, this measure of the stimulated volume does not take into account the properties of the fracture network, which has also been indicated to impact well performance (Mayerhofer et al. 2006). Furthermore, the permeability enhancement of the fracture may be related to deformation associated with fracturing. Beyond the basic hypocentral locations of the microseisms used to calculate the SRV, additional seismic signal characteristics allow investigation of the source of the mechanical deformation resulting in the microseisms. In particular, the seismic moment (Aki and Richards 1980), a robust measure of the strength of an earthquake or microearthquake can be used to quantify the seismic deformation (Maxwell et al. 2003).
In this paper, we examine several published microseismic projects in the Barnett Shale formation for correlation between the production and seismic-deformation attributes. In the next section, we describe seismic moments and the calculation of seismic deformation. We illustrate how a seismic moment can be used to remove a recording bias present in most microseismic monitoring applications and the importance for calculating the seismic deformation. Finally, we present the comparison between production, seismic deformation, and SRV for several published datasets.
Investigation of the Flow Properties of CBM Based on Stochastic Fracture Network Modeling
