Interstitial Gas

Key Takeaways

• Interstitial gas saturation in coal seam reservoirs (coalbed methane, CBM) depends on the cleat porosity (the network of orthogonal natural fractures -- face cleats and butt cleats -- that constitute the permeability system in coal), the cleat water saturation (coal seams are typically water-saturated in the cleat system at initial reservoir conditions, with water the primary occupant of the interstitial pore space), and the free gas saturation (the fraction of cleat pore volume occupied by gas rather than water): at initial reservoir conditions, most coal seam reservoirs are at or near the critical desorption pressure (where the reservoir pressure just equals the desorption pressure corresponding to the current gas content on the coal's adsorption isotherm), meaning little or no free gas exists in the cleat system (the system is at the adsorption isotherm endpoint) and the interstitial gas content is near zero; as dewatering proceeds and reservoir pressure declines below the critical desorption pressure, gas begins to desorb from the coal matrix and accumulates in the cleat system as interstitial free gas, with the gas saturation increasing from zero to near-residual water saturation as the dewatering program matures over months to years; the rate of interstitial gas accumulation relative to the rate of pressure decline (and hence the rate of gas production rise relative to the rate of water production decline) depends on the coal matrix diffusion coefficient (how fast methane diffuses from the coal matrix through micropores to the cleats) and the cleat permeability (how fast the water and gas move through the cleats to the wellbore).
• Desorption canister analysis for total gas content measurement captures both adsorbed and interstitial gas components from freshly recovered core samples, but the two components cannot be directly separated during the standard desorption test: when a core sample is placed in a sealed canister immediately after retrieval from the wellbore, gas begins to desorb from both the adsorbed phase (released as pressure drops from reservoir pressure to atmospheric during core recovery) and the interstitial free gas (released from pores as the pore pressure equilibrates to atmospheric); the gas collected in the canister from the time of core retrieval to the end of desorption (typically over 2 to 7 days at ambient temperature until evolution rate drops below 0.05 cc/min) is the measured desorbed gas; the lost gas (the gas that desorbed during core recovery before the sample was sealed in the canister) is estimated by extrapolation of the cumulative desorption curve back to time zero (using a square-root-of-time extrapolation or a more sophisticated desorption model); the interstitial gas fraction of the total measured content can be estimated from the reservoir pressure, water saturation, and cleat porosity using the ideal gas law (P*V = n*R*T) if these parameters are known from well logs and core analysis, but direct measurement of only the interstitial component requires special core handling (freezing the sample in liquid nitrogen immediately after retrieval, which freezes both the water and the interstitial gas in place, then measuring only the released gas from the frozen sample under controlled pressure conditions -- a technique not commonly used in routine CBM core analysis).
• The proportion of interstitial gas to adsorbed gas in shale gas reservoirs depends on the organic richness, thermal maturity, pore size distribution, and reservoir pressure of the specific formation: in the Barnett Shale (Fort Worth Basin, Texas), the classic first commercial shale gas play, the adsorbed gas fraction is approximately 20 to 80 percent of total GIP (varying with organic carbon content and depth), with the remainder being interstitial free gas compressed in the micro- and mesopores of the shale matrix and in natural fractures; in high-pressure, low-maturity shale formations (where the organic matter has abundant microporosity from immature kerogen but has not undergone sufficient thermal cracking to generate large volumes of methane), interstitial free gas in the matrix pores may represent 40 to 60 percent of total gas content; in very high-maturity (overmature) formations where most of the kerogen has been converted to methane and secondary graphite, the organic pore network is highly developed (nanometer-scale pore radii in bitumen-derived pores as observed in the Haynesville, Eagle Ford, and Duvernay shales), providing substantial micropore volume for both adsorption and compressed interstitial gas storage at high pressure; correct quantification of the adsorbed versus interstitial split is important for reserve estimation (the two gas types have different production profiles -- adsorbed gas requires pressure drawdown below the desorption pressure to produce, while interstitial gas can be produced as long as reservoir pressure is maintained above abandonment pressure) and for decline curve analysis (which behaves differently for adsorption-dominated versus free gas-dominated systems).
• Gas content measurement methods used to determine interstitial and adsorbed gas fractions include desorption canister analysis (the standard industry method for core samples), direct measurement of coal gas content using gas chromatography of core plugs (for composition), sorption isotherm measurement (to characterize the adsorption capacity and Langmuir isotherm parameters that relate adsorbed gas to reservoir pressure), and geophysical log interpretation (using density, neutron, resistivity, and gas log responses to estimate total porosity, water saturation, and hence interstitial gas saturation at each depth level from the log curves): sorption isotherms (measured in the laboratory on crushed coal or shale samples at reservoir temperature using a manometric or volumetric adsorption apparatus) define the Langmuir isotherm relationship between adsorbed gas volume (in cc/g or scf/ton) and pressure, allowing the adsorbed gas content at any reservoir pressure to be calculated; the interstitial gas content is the difference between the total gas content (from desorption canister or core analysis) and the adsorbed gas content (from the Langmuir isotherm at reservoir pressure); Langmuir isotherm parameters (the Langmuir volume VL and the Langmuir pressure PL) are the industry-standard parameters for characterizing adsorption capacity and are used in reservoir simulation models for CBM and shale gas to compute gas content at each pressure step during depletion.
• Reservoir simulation of CBM and shale gas fields must distinguish interstitial and adsorbed gas behavior because the two storage mechanisms respond differently to pressure depletion: interstitial free gas in the cleat or fracture network expands according to the real gas equation of state (with compressibility factor Z from the Peng-Robinson or van der Waals EOS) as pressure declines, providing immediate gas production response when reservoir pressure decreases; adsorbed gas desorbs gradually from the matrix surface as pressure falls below the desorption pressure, with the rate of desorption limited by matrix diffusion (Fick's law, with a diffusion time constant that may range from days to years depending on the coal rank and pore structure); the dual-porosity, dual-permeability reservoir simulation model (used for CBM and naturally fractured shale gas) treats the cleat/fracture system and the coal/shale matrix as two interacting continua, with the interstitial gas in the cleat system flowing through the fracture network to the wellbore and the adsorbed gas desorbing from the matrix and diffusing into the cleat system under the influence of the concentration gradient created by desorption; the matrix-to-cleat transfer function (the shape factor controlling how quickly gas transfers from the matrix to the fracture) is the most sensitive parameter in CBM reservoir simulation and is typically calibrated to production history data, with values that vary over several orders of magnitude for different coal ranks, seam thicknesses, and cleating patterns.