Permeability anisotropy in a coal seam in the Bowen Basin has been measured by a multiple well interference test. The degree and orientation of the anisotropy was apparently influenced by coal structural features on various scales. Simulations of the field observations using a two-phase dual porosity model confirmed the single-phase interference test analysis, and also simulated various aspects of the seam response to subsequent stimulation treatments involving two-phase fluid injections. The influences on reservoir response of reservoir heterogeneity, relative permeability and flow localisation are discussed with respect to the application of continuum modelling concepts.


Naturally occurring fracture systems in coal occur on a range of scales. The fractures have much higher fluid conductivities than the coal matrix and generally control the fluid transport properties. The most pervasive natural fracture system is the cleat system, formed mainly in bright coal by orthogonal sets of face and butt cleats, lying in planes normal to bedding. These define a blocky structure within the coal, which because of the more planar and continuous nature of the face cleat relative to the butt cleat, can result in strong permeability anisotropy This is reflected in measured anisotropy ratios as high as 17:1 in the plane of the seams.

Permeability is one of the most important factors controlling the production of coalbed methane (CBM), and efficient stimulation is generally required to obtain adequate gas production rates. Hydraulic fracturing is the commonly applied stimulation method. An alternative technique, openhole cavity completion, may be successful if conditions are suitable. In either case, the presence of horizontal anisotropy in the permeability field can strongly affect the efficiency of the stimulation, and needs to be considered in the stimulation design and the production well layout.

In assessing the likely orientation of permeability anisotropy in a coalbed methane reservoir, it is often assumed that the major permeability axis will parallel the face cleat direction which in turn is assumed to parallel the direction of the major horizontal principal stress. The direction of the major principal stress might be estimated by measurement of hydraulic fracture orientation in a minifrac test in the bounding sediments of the seam, and the major permeability axis inferred from the stress direction. Alternatively, core orientation methods may provide the cleat direction directly. However, these methods may not account for other influences on permeability orientation, such as the effect of broader scale fracture systems, or the coupled effects of the structures with the stress regime and pore fluid pressure gradients.

During an investigation and trial of stimulation by cavity completion carried out in the Bowen Basin, detailed reservoir response to the process was investigated. Reservoir characterisation undertaken before stimulation included direct measurements of permeability anisotropy by interference testing in multiple observation wells. Subsequently, during stimulation operations, both water and air were injected using a range of rates, pressures and durations, including highly dynamic, short duration events. Data from the active wells and the observation wells were continuously recorded throughout the operations. Analysis of permeability anisotropy based on the response of the observation wells was carried out using both standard analytical methods and numerical simulations.

This paper presents the field data in the context of the target seam conditions and compares estimates of permeability anisotropy from the standard analysis of the single-phase interference tests with the values obtained by numerical simulation of the complex two-phase injection history. The limits of continuum analysis in terms of the scale effects of coal structures, mechanical-fluid flow coupling and flow localisation and the implications for coalbed methane reservoir characterisation are discussed.

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