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Finite-difference modelling of microseismicity associated with a hydraulic-fracturing stimulation in a coalbed methane reservoirNormal access

Authors: Germán Rodríguez-Pradilla and David W. Eaton
Journal name: First Break
Issue: Vol 36, No 4, April 2018 pp. 41 - 48
Special topic: Passive Seismic
Language: English
Info: Article, PDF ( 1.03Mb )
Price: € 30

Owing to the large capacity for matrix storage, substantial volumes of methane gas are stored in coal beds in the form of adsorbed gas (Nuccio, 2000). According to Langmuir’s theory that relates the adsorbed gas volume to the reservoir pressure (Langmuir, 1918), a fast dewatering process is required to achieve rapid reduction of the reservoir pressure and thus to release the adsorbed methane gas (Anderson and Simpson, 2003). The effectiveness of this dewatering process depends on the coal permeability, which is mostly related to the aperture and spacing of its natural fractures (or cleats). Coal permeability is highly stress-sensitive. For example, a coal sample with a cleat aperture of 10 μm and a permeability of 1000 millidarcy at surface conditions (no in-situ stress) can be reduced to a cleat aperture of less than 1 μm and a permeability of less than 1 millidarcy at reservoir conditions, assuming 50% lithostatic pressure and a mean pore pressure of 1 MPa (Weniger et al., 2016). This low permeability of coal beds due to fracture closure makes hydraulic fracturing necessary, to increase the fracture frequency and width in order to achieve economic gas production rates; for this reason, hydraulic fracturing has been implemented for stimulation of coalbed methane reservoirs for decades (e.g. Holditch et al., 1988). Microseismic monitoring is an effective method for assessing hydraulic-fracturing treatments and has proven to be a key technology to image the propagation of hydraulic fractures within a reservoir (Maxwell, 2014). Previous microseismic studies in coal-bearing reservoirs, however, have encountered challenges because of the complex velocity model of low-velocity, low-density coal beds interbedded within more rigid clastic units. Consequently, finite-difference (FD) modelling has proven to be a very useful tool to understand complex seismic propagation and interference patterns (Pike, 2014). This case study focuses on the analysis of microseismic data from a CBM reservoir located close to the northern limit of Cesar-Ranchería Basin, Colombia. The microseismic data was acquired at the surface using two perpendicular lines of vertical-component geophones (Figure 1). Clear P-wave arrivals with reverberating waveform character are evident, but no clear S-wave arrivals are discernible in the data. A 2D-FD waveform modelling approach was used to calibrate a velocity model based on data from the reservoir (well logs and seismic-reflection data) and on the recorded microseismic data from the hydraulic-fracturing treatment. A 1D isotropic velocity model was implemented for this case study, as this degree of approximation has been reported to be sufficiently accurate for microseismic event location in similar case studies of surface microseismic monitoring (e.g. Neuhaus et al., 2012). Numerical simulation using a 2D-FD approach is considerably less time-consuming when compared with full 3D-FD modelling. Moreover, the linear alignment of the surface monitoring array, together with the implementation of a 1D isotropic velocity model, makes the implementation of 2D-FD modelling feasible for calibrating the velocity model.

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