Adsorbed Gas
Adsorbed gas is natural gas (primarily methane) that is held on the internal surfaces of a porous solid material by intermolecular attractive forces rather than existing as a free compressible gas phase in the open pore space. In the context of oil and gas reservoirs, adsorption occurs when gas molecules are attracted to and accumulate on the surfaces of organic matter (kerogen, bitumen) and clay minerals within the reservoir rock, forming a thin concentrated layer of gas molecules that is distinct from the free gas stored in the pore volume between those surfaces. The quantity of gas adsorbed per unit mass of rock depends on the reservoir pressure, the temperature, and the affinity of the rock surface for the gas molecules, described quantitatively by the adsorption isotherm measured at reservoir temperature. Coal bed methane (CBM) reservoirs store nearly all of their gas in the adsorbed state on the internal surfaces of coal matrix blocks; organic-rich shale gas reservoirs store a significant fraction of their total gas in place (typically 20 to 50 percent) as adsorbed gas on kerogen and clay surfaces. Understanding adsorbed gas is critical to correct gas-in-place estimation, desorption behaviour during production, and the design of dewatering or pressure-maintenance strategies for CBM wells.
Key Takeaways
- The Langmuir adsorption isotherm is the standard model for quantifying adsorbed gas in coal and shale: V_ads = V_L × P / (P + P_L), where V_ads is the volume of gas adsorbed per unit mass of rock at pressure P (in standard cubic metres per tonne or scf per ton), V_L is the Langmuir volume (the maximum monolayer adsorption capacity, representing the adsorbed gas volume as P approaches infinity), and P_L is the Langmuir pressure (the pressure at which the adsorption is half the maximum capacity). Typical values for coal in the WCSB Horseshoe Canyon and Mannville formations: V_L of 14 to 28 scm³/tonne and P_L of 0.8 to 2.5 MPa on a dry, ash-free basis; typical values for Duvernay or Montney organic-rich shale: V_L of 2 to 8 scm³/tonne and P_L of 2 to 6 MPa on a total organic carbon (TOC)-weighted basis. The steepness of the Langmuir curve at low pressure (determined by V_L/P_L) governs how rapidly desorption occurs during pressure depletion, which controls the rate of gas supply from desorption to the fracture network and ultimately to the wellbore.
- The critical desorption pressure is the reservoir pressure at which gas begins to desorb from the solid surfaces in quantity sufficient to affect production. For CBM reservoirs, the initial reservoir pressure is typically above the critical desorption pressure, meaning the reservoir is undersaturated with respect to adsorption (the coal is not at its maximum adsorption capacity for the initial gas composition and temperature). To initiate gas production from a CBM well, water must first be produced to reduce reservoir pressure below the critical desorption pressure; during this dewatering phase, the well produces increasing water rates with minimal gas until pressure drops sufficiently for desorption to begin. The dewatering period can last 6 to 24 months in CBM wells, which is a significant capital and operational cost consideration for CBM development. For shale gas wells, the reservoir is often already below the critical desorption pressure at initial conditions (the reservoir is adsorption-saturated), meaning desorption begins immediately when the well is put on production and contributes to gas supply from the earliest stages of production.
- Moisture content strongly affects the adsorption capacity of coal for methane. Water molecules compete with methane molecules for adsorption sites on the coal surface, and water is preferentially adsorbed because it has stronger polar interactions with the hydrophilic coal surface than non-polar methane. Laboratory measurements of V_L on dried coal samples significantly overestimate the adsorption capacity at reservoir moisture conditions: a coal with a dry V_L of 25 scm³/tonne may have a moisture-equilibrated V_L of only 15 scm³/tonne at its in-situ equilibrium moisture content (typically 6 to 12 percent for Horseshoe Canyon coals). Adsorption isotherms used for gas-in-place calculations must be measured on as-received or moisture-equilibrated samples rather than on oven-dried samples to avoid overestimating adsorbed gas in place. The error from using dried-coal isotherms in CBM gas-in-place estimates has led to material reserve overstatements in several CBM development areas, which is why WCSB regulatory and engineering practice now universally requires moisture-equilibrated isotherm measurements for reserves certification.
- The extended Langmuir model is used when the gas is a mixture (methane plus CO2, nitrogen, ethane, or heavier components) because each species competes for adsorption sites. For pure methane systems, the Langmuir model adequately describes adsorption. In coalfields where CO2 injection is used for enhanced CBM recovery (ECBM), CO2 is preferentially adsorbed over methane (CO2 has a higher affinity for coal surfaces, with V_L(CO2) approximately 2 to 3 times V_L(CH4) for the same coal), and injected CO2 displaces adsorbed methane from the coal surface, mobilising it for production. This preferential adsorption of CO2 relative to methane is the physical basis of CO2-ECBM, which has been piloted in the Horseshoe Canyon Formation in the Crossfield area of Alberta and in coal seams in British Columbia. The extended Langmuir model correctly predicts the competitive adsorption between CH4 and CO2 and is required to model ECBM desorption responses.
- Total gas in place for shale gas reservoirs is the sum of free gas in the pore volume (calculated using the real gas law from porosity, water saturation, pressure, temperature, and gas compressibility factor), adsorbed gas on organic matter and clays (calculated from the Langmuir isotherm calibrated to total organic carbon content), and dissolved gas in formation water and residual oil (typically minor). The adsorbed gas fraction depends on the total organic carbon content (TOC) of the shale: high-TOC shales (5 to 15 percent by weight, such as the Duvernay and Muskwa) have more adsorption surface area per unit mass and thus higher adsorbed gas content relative to free gas than low-TOC shales (1 to 3 percent). In the Duvernay Formation, adsorbed gas can represent 25 to 40 percent of total gas in place at typical reservoir pressures (40 to 60 MPa); neglecting the adsorbed gas component in Duvernay gas-in-place calculations would underestimate the total resource by this fraction, which at field scale can represent hundreds of billions of cubic metres of gas.
Desorption During Production: The Gas Supply Mechanism
As reservoir pressure declines during production (either from water production in CBM or gas production in shale), the adsorption equilibrium established at initial conditions is disturbed: the local gas pressure is now lower than the initial equilibrium pressure, so the adsorption isotherm predicts a lower adsorbed gas content at the new pressure than was present initially. The difference in adsorbed gas between the initial and current pressure must have desorbed into the free gas phase, adding to the gas available for flow toward the wellbore. The rate of this desorption depends on the rate of pressure decline and on the diffusion coefficient governing how quickly gas molecules migrate from the adsorption sites on the internal surface of coal matrix blocks or shale organic matter to the macropore or natural fracture network.
In coal, the diffusion path is from the microporous coal matrix (where adsorption occurs) through the coal grain to the cleat network (the system of natural fractures that provides the primary flow conduits in coal bed methane). The diffusion coefficient for methane in coal matrix is typically 10⁻¹⁴ to 10⁻¹¹ m²/s, depending on coal rank and matrix block size. For a coal with cleat spacing of 5 centimetres (matrix block dimension 2.5 centimetres), the diffusion time constant (square of half-spacing divided by diffusivity) is 10 to 10,000 seconds, meaning that desorption and diffusion to the cleat face can follow pressure changes on timescales of minutes to hours in fast-desorbing coals but can lag by days or weeks in slow-desorbing coals. In shale, the organic matter is much more finely distributed (nanometre-scale kerogen pores) and the diffusion path lengths to the natural fracture network are very short, so desorption in shale is typically fast relative to the production timescale.
CBM Gas-in-Place Calculation Including Adsorbed Gas
The gas initially in place (GIIP) for a coalbed methane reservoir includes two components. The first is the adsorbed gas: GIIP_ads = h × rho_b × A × (1 - Sh) × V_ads(Pi), where h is the seam thickness, rho_b is the bulk density of the coal (approximately 1.3 to 1.5 tonne/m³), A is the drainage area, Sh is the ash fraction, and V_ads(Pi) is the Langmuir isotherm evaluated at initial reservoir pressure Pi. The second is the free gas in the cleat porosity: GIIP_free = h × phi_cleat × (1 - Sw) × A / (Bg), where phi_cleat is the cleat porosity (typically 0.5 to 2 percent), Sw is the cleat water saturation (typically near 1 for an undersaturated CBM reservoir), and Bg is the gas formation volume factor at reservoir conditions. In most CBM reservoirs, GIIP_ads is 90 to 98 percent of the total GIIP because cleat porosity is very low and most of the gas resides on coal matrix surfaces.
Fast Facts
Coal bed methane was first produced commercially in the San Juan Basin of New Mexico and Colorado in the 1980s following the US federal methane-from-coal tax credit that made CBM wells economically viable. In Canada, CBM development was concentrated in the Horseshoe Canyon Formation of southern Alberta (a low-pressure, low-depth CBM play amenable to dewatering) during the 2000s, with production peaking at approximately 5 billion cubic feet per day in the mid-2000s before declining due to price and cost factors. Adsorption isotherm measurement for reservoir characterisation was standardised by the American Society for Testing and Materials (ASTM D7569) and the Gas Research Institute (GRI); the protocols specify sample preparation, equilibration temperature, step-wise pressure increments, and measurement of both excess and absolute adsorption. The Langmuir isotherm model was originally published by Irving Langmuir in 1916 as a description of gas adsorption on clean surfaces at low coverage; its adoption by the petroleum engineering community for coal and shale gas was a direct consequence of its simplicity and reasonable accuracy across the pressure ranges relevant to CBM and shale gas production (0 to 20 MPa). Research programs at the University of Alberta and the Alberta Geological Survey have produced regional Langmuir isotherm compilations for the Horseshoe Canyon, Mannville, and Ardley coal zones that provide baseline adsorption parameters for CBM resource assessments across the WCSB.
Synonyms and Related Terminology
Adsorbed gas is also called sorbed gas, matrix gas, or desorbed gas (when referring to the gas released during production). In CBM, it may be called stored gas or coal gas. Related terms include Langmuir isotherm (the standard model for gas adsorption on coal and organic matter surfaces: V_ads = V_L × P/(P + P_L); requires two parameters measured on core at reservoir temperature, the Langmuir volume V_L (maximum adsorption capacity) and the Langmuir pressure P_L (pressure at half-maximum adsorption); used to compute adsorbed gas in place as a function of reservoir pressure), coal bed methane (CBM, natural gas stored primarily as adsorbed gas on the internal surfaces of coal seams; produced by dewatering the coal cleat network to reduce reservoir pressure below the critical desorption pressure, releasing adsorbed methane from the coal matrix; the dominant unconventional gas resource in the Horseshoe Canyon and Mannville formations of Alberta), desorption (the release of adsorbed gas molecules from the solid surface into the free gas phase as reservoir pressure declines below the adsorption equilibrium pressure; the inverse of adsorption; the gas supply mechanism that sustains production from coal and organic-rich shale formations after the free gas in the pore network has been depleted), total organic carbon (TOC, the mass fraction of organic carbon in a shale or coal, expressed as percentage by weight; controls the adsorption surface area available for gas adsorption and therefore the adsorbed gas content per unit mass of rock; high-TOC intervals (greater than 3 percent) contribute disproportionately to adsorbed gas in place in shale gas formations), and critical desorption pressure (the reservoir pressure at which gas begins to desorb from coal or shale surfaces in quantities sufficient to flow through the cleat or fracture network and contribute to wellbore production; below this pressure the production profile transitions from purely dewatering-driven in CBM to gas-dominated; its value is determined from the Langmuir isotherm at the initial adsorbed gas content).