This article reviews the storage of captured CO2 in coal seams. Other geologic formations, such as depleted petroleum reservoirs, deep saline aquifers and others have received considerable attention as sites for sequestering CO2. This review focuses on geologic sequestration of CO2 in unmineable coalbeds as the geologic host. Key issues for geologic sequestration include potential storage capacity, the storage integrity of the geologic host, and the chemical and physical processes initiated by the deep underground injection of CO2. The review topics include (i) the estimated CO2 storage capacity of coal, along with the estimated amount and composition of coalbed gas; (ii) an evaluation of the coal seam properties relevant to CO2 sequestration, such as density, surface area, porosity, diffusion, permeability, transport, rank, adsorption/desorption, shrinkage/swelling, and thermochemical reactions; and (iii) a treatment of how coalbed methane (CBM) recovery and CO2-enhanced coalbed methane (ECBM) recovery a...

Sequestration of Carbon Dioxide in Coal with Enhanced Coalbed Methane RecoveryA Review

The gas permeability of a coalbed, unlike that of conventional gas reservoirs, is influenced during gas production not only by the simultaneous changes in effective stress and gas slippage, but also by the volumetric strain of the coal matrix that is associated with gas desorption. A technique for conducting laboratory experiments to separate these effects and estimate their individual contribution is presented in this paper. The results show that for a pressure decrease from 6.2 to 0.7 MPa, the total permeability of the coal sample increased by more than 17 times. A factor of 12 is due to the volumetric strain effect, and a factor of 5 due to the gas slippage effect. Changes in permeability and porosity with gas depletion were also estimated using the measured volumetric strain and the matchstick reservoir model geometry for flow of gas in coalbeds. The resulting variations were compared with results obtained experimentally. Furthermore, the results show that when gas pressure is above 1.7 MPa, the effect of volumetric strain due to matrix shrinkage dominates. As gas pressure falls below 1.7 MPa, both the gas slippage and matrix shrinkage effects play important roles in influencing the permeability. Finally, the change in permeability associated with matrix shrinkage was found to be linearly proportional to the volumetric strain. Since volumetric strain is linearly proportional to the amount of gas desorbed, the change in permeability is a linear function of the amount of desorbing gas.

Influence of gas production induced volumetric strain on permeability of coal

Various flow regimes including Knudsen, transition, slip and viscous flows (Darcy’s law), as applied to flow of natural gas through porous conventional rocks, tight formations and shale systems, are investigated. Data from the Mesaverde formation in the United States are used to demonstrate that the permeability correction factors range generally between 1 and 10. However, there are instances where the corrections can be between 10 and 100 for gas flow with high Knudsen number in the transition flow regime, and especially in the Knudsen’s flow regime. The results are of practical interest as gas permeability in porous media can be more complex than that of liquid. The gas permeability is influenced by slippage of gas, which is a pressure-dependent parameter, commonly referred to as Klinkenberg’s effect. This phenomenon plays a substantial role in gas flow through porous media, especially in unconventional reservoirs with low permeability, such as tight sands, coal seams, and shale formations. A higher-order permeability correlation for gas flow called Knudsen’s permeability is studied. As opposed to Klinkenberg’s correlation, which is a first-order equation, Knudsen’s correlation is a second-order approximation. Even higher-order equations can be derived based on the concept used in developing this model. A plot of permeability correction factor versus Knudsen number gives a typecurve. This typecurve can be used to generalize the permeability correction in tight porous media. We conclude that Knudsen’s permeability correlation is more accurate than Klinkenberg’s model especially for extremely tight porous media with transition and free molecular flow regimes. The results from this study indicate that Klinkenberg’s model and various extensions developed throughout the past years underestimate the permeability correction especially for the case of fluid flow with the high Knudsen number.

Knudsen’s Permeability Correction for Tight Porous Media

Effect of pressure and temperature on diffusion of CO2 and CH4 into coal from the Lorraine basin (France)

Modeling of Fluid Transfer From Shale Matrix to Fracture Network

A mathematical formulation, applicable to both numerical simulation and transient well analysis that describes the flow of gas in very tight porous media and includes a dual-mechanism transport of gas is developed. Gas is assumed to be traveling under the influence of a concentration field and a pressure field. Transport through the concentration field is a Knudsen flow process and is modeled with Fick's law of diffusion. Transport through the pressure field is a laminar process and is modeled with Darcy's law (inertial/turbulent effects are ignored). The combination of these two flow mechanisms rigorously yields a composition-, pressure-, and saturation-dependent slippage factor. The pressure dependence arises from treating the gas as a real gas. The derived dynamic slippage is most applicable in reservoirs with permeabilities less than or equal to0.01 md. The results indicate that in reservoirs of this type, differences between recoveries after 10 years of production with the dynamic-slip and constant-slip approaches were as great as 10%, depending on the initial gas saturation. If an economic production rate is considered, differences as great as 30% can be expected.

Dynamic gas slippage: a unique dual-mechanism approach to the flow of gas in tight formations.

Described in this paper are the mathematical and numerical developments for a series of finite difference models which simulate the two-phase, transient behavior of coal seam degasification wells. Included in this series are models for unstimulated, as well as hydraulically stimulated, wells. The hydraulically stimulated wells are assumed to have either a single infinite or finite conductivity vertical fracture. The natural fracture system of the coal seam, the butt and face cleat, is identified with a porous network and assigned effective porosities, nominally less than ten percent, and absolute permeabilities, generally less than 25 md with values extending into the microdarcy range. A time dependent sorption term has been included to describe the phenomenon of gas desorbing from the coal matrix to the porous network. The coal seam is then modeled with the mathematics of multiphase flow through porous media. All models described in this paper are single well, mesh centered models in radial-cylindrical coordinate geometry. The fully implicit, generalized Newton-Raphson procedure has been employed to solve the coupled, nonlinear equations generated by the models. An intensive sensitivity analysis of the models is included. All models have been verified with successful history matches against stimulated and unstimulated methane drainage wellsmore » producing from coal gas reservoirs.« less

Numerical simulation of the transient behavior of coal-seam degasification wells

The production performances of horizontal drainage wells for the degasification of coal seams have been investigated with a multidimensional, two-phase coal-seam degasification model. The model is written in rectangular coordinates, can handle a number of horizontal wells, and operates in a one-, two-, or three-dimensional (1D, 2D, or 3D) mode. The model accommodates multiple horizontal boreholes originating from a common vertical shaft or horizontal boreholes being drilled from the peripheries of the reservoir. In consideration of the relatively thin but large lateral extent of coal seams, flow dynamics around a horizontal borehole is described in elliptic flow geometry. The nonlinear system of equations generated by the finite-difference approximation is solved fully implicitly with Newton's iteration. A series of computer runs was conducted systematically to demonstrate the relative significance of different reservoir and fluid characteristics on the negative and positive decline features of horizontal drainage wells. Along these lines, the effects of coal-seam properties - such as thickness, porosity, permeability, and sorption characteristics - and horizontal borehole parameters - such as hole diameter, penetration length, and positioning of the borehole - have been isolated to understand the role of each individual parameter on the production performance of horizontal drainage wells. Contrarymore » to the design of a vertical fracture, the orientation of the horizontal borehole with respect to face and butt cleats is controllable. Results of another series of runs are presented for different orientations of horizontal boreholes with respect to the principal directions of the natural fracture network to maximize the recovery of methane from coal seams through horizontal boreholes.« less

Production performance analysis of horizontal drainage wells for the degasification of coal seams

The production performances of horizontal drainage wells for the degasification of coal seams have been investigated with the aid of a multidimensional, two-phase coal seam degasification model. The model is written in rectangular coordinates and can handle a number of horizontal wells and operates in a one-, two-, or three-dimensional mode. The model accommodates multiple horizontal boreholes originating from a common vertical shaft or horizontal boreholes being drilled from the peripheries of the reservoir. In consideration of relatively thin but large lateral extent of coal seams, flow dynamics around a horizontal borehole is described in elliptical flow geometry. The non-linear system of equations generated by the finite difference approximation are solved fully implicitly using Newton's iteration. In the mathematical formulation of the problem, coal seam was treated as a dual-porosity system. Transport of methane in the micropore structure of the coal was described by Fick's Law of diffusion while flow in the more permeable natural fracture network of the coal seam was formulated by Darcy's Law. A quasi-steady state kinetic model was included to represent the desorption of methane from coal grains.

F.C. Schwerer

Papers

Dynamic gas slippage: a unique dual-mechanism approach to the flow of gas in tight formations.

Numerical simulation of the transient behavior of coal-seam degasification wells

Production performance analysis of horizontal drainage wells for the degasification of coal seams

Production performance analysis of horizontal drainage wells for the degasification of coal seams

Measurement of Coalbed Properties for Hydraulic Fracture Design and Methane Production