This technical note highlights the storage mechanisms of gas in shale and outlines methods for determining gas-in-place from field and laboratory methods. A predictive model has been developed that can estimate gas-in-place using mineralogy, fundamental geochemical properties and best estimates of current in-situ temperature and pressure.
There are direct and indirect methods for estimating gas-in-place. We are familiar with direct methods— such as canister desorption— where a physical core sample is recovered and the evolved gas is measured. After correcting for gas lost during recovery and residual gas, total gas-in-place can be locally determined. Alternatively, if core is not available, or if exploration and appraisal data are available, indirect methods have appeal. One type of indirect method is well logging. Another indirect method is predictive modeling. The predictions can be based on mineralogy (from logs, full diameter or sidewall core, cuttings, whatever is available), geochemical properties (TOC and RO, determined from whatever formation material or logs are available) and reservoir properties (temperature and pressure). Basin history is not explicitly accounted for.
Isotherm measurements can be carried out on reservoir material to infer the formation’s adsorptive storage capacity. Schettler and Parmely (1991) conducted adsorption isotherm experiments on “end-members” (sandstones, limestones, clay mixtures) and shale samples of varying maturity (Green River and Marcellus), over a range of temperatures and water saturations. Along with other isotherms collected from literature surveys, a general semi-analytical model was developed to estimate gas-in-place (GIP) at different reservoir conditions using petrophysical and geochemical properties (mineralogical compositions, TOC content, maturity). The software model allows direct estimation of adsorption isotherms at any reservoir conditions. Total gas-in-place includes this as one component, along with minor dissolution in liquid phases, and dominant compressible storage in porosity.
Low and ultra-low permeability shale gas reservoirs are an established part of many portfolios. Keys to success are adequate gas-in-place (GIP), adequate in-situ conductive systems (existing or latent fracture systems, discontinuities or higher permeability zones), and appropriate stimulation methodologies for creating interconnected surface area. During the exploration phase of a shale gas play, it is necessary to assess shale gas potential for booking reserves and an estimate of the GIP is a key component in assessing that potential.
Any fine-grained, organic-rich sediment that has been buried deep enough to generate and expel gas can be considered a possible thermogenic shale gas play. Expulsion efficiency distinguishes a source rock in conventional and unconventional petroleum systems. In a conventional petroleum system, a high-quality source rock has implicitly generated and expelled a significant amount of its hydrocarbons. In a shale gas unconventional petroleum system, a high-quality source rock has generated and retained a significant portion of these generated products. Assuming that the shale has generated and retained a significant quantity of gas/oil, there are several geological and geochemical factors that can influence total shale gas reserves. These are: organic matter content, maturity, reservoir pressure and temperature, mineralogy, gas composition, and porosity. All of these come to bear on the amount of gas in the shale and how that gas is stored.
Shale gas can be stored by three primary mechanisms: (a) void storage – in which the (free) gas is compressed in the pore spaces of the rock and organics in accordance with in-situ pressure, temperature and burial history; (b) dissolution – in which gas is dissolved in other phases (oil, brine) that may be present in the pores; and (c) adsorption – in which gas is adsorbed onto the surface of various rock minerals or organic constituents. The first two mechanisms are dominant in conventional gas/oil reservoirs and their contributions to total gas-in-place can be “easily” deduced. By contrast, at the other extreme, in coalbed methane reservoirs gas is stored essentially by adsorption. In shale gas reservoirs, we expect that gas is stored mainly as free gas and as adsorbed gas, but their relative importance may vary widely from play to play.
Adsorption is the least understood and the largest source of uncertainty for shale gas reserves estimation and production. The main complication is that adsorption is a surface phenomenon; knowledge of the rock/pore volume alone (estimated from seismic, well logs) is not sufficient to infer gas adsorption. Current GIP estimates therefore rely on well site measurements and/or laboratory experiments on reservoir samples.
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To cite this article:
McLennan, J. and Segall, M. (2019). Analytical Prediction of Gas-in-Place (GIP): Improved Technologies for Shale Gas Systems (SGS). ASK EGI, Vol. 5:2, Energy & Geoscience Institute at the University of Utah.