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Phase Transitions Involving Methane in Sorbed Gas Reservoir Systems

Levine, Jeffrey 1
1 [email protected], Consultant Geologist, Richardson, TX.

Typical models of sorbed gas reservoirs (CBM and shale gas) do not accurately or adequately depict the phase behavior of the system. CBM reservoirs are usually described as microporous solids containing adsorbed gas, but are better described as multiphase, multicomponent systems, where methane is partitioned in dynamic equilibrium among two or more phases, including two condensed phases phases: 1) an aqueous phase (Φaq; liquid) and 2) organic matter phase(s) (Φom; solid and/or fluid). If conditions are favorable, a free gas phase (Φg) may also be present. Methane occurring in Φom is adsorbed and/or dissolved, depending on the physical state of the organic matter, hence is best described as “sorbed” (without a prefix). The thermodynamic properties of methane are different in each phase. Accordingly, altering the system P & T causes a flux of methane between phases. The same relationships describe the phase behavior of methane in shale gas systems.

A methane sorption isotherm depicts the concentration of sorbed methane as a function of methane pressure. A diagram similar in appearance, which plots total methane in the system versus total system pressure, can be used to depict transitions among methane-bearing phases. Here, the isotherm represents the equilibrium vapor pressure curve, or “bubble point curve”, separating a two phase region (Φaq+Φom) on the high pressure side from a three phase region (Φg+Φaq+Φom) on the low pressure side. Reservoir systems plotting in the 2Φ region are described as “undersaturated”, and those in the 3Φ region as “supersaturated”.

During production from undersaturated reservoirs, a distinct methane-rich gas phase, Φg, will form when the phase boundary is encountered (bubble point pressure). In contrast with typical reservoir models, the system does not then follow the isotherm with further reduction in pressure, but crosses into the 3Φ region. Φg can form not only in the fracture network, as usually depicted, but within the matrix as well, especially for low rank coals having high macroporosity. Owing to its high compressibility Φg can expel liquids from the matrix as it expands with further reduction in pressure--a mechanism termed "solution gas drive" in black oil reservoirs. Water expelled from the matrix contributes to total water production, as evidenced by production modeling from the Powder River Basin and Antrim Shale.

 

AAPG Search and Discovery Article #90090©2009 AAPG Annual Convention and Exhibition, Denver, Colorado, June 7-10, 2009