Shale Gas-in-Place Calculations Part I: New Pore-Scale Considerations

Abstract

Summary Using focused-ion-beam (FIB)/scanning-electron-microscope (SEM) imaging technology, a series of 2D and 3D submicroscale investigations revealed a finely dispersed porous organic (kerogen) material embedded within an inorganic matrix. The organic material has pores and capillaries having characteristic lengths typically less than 100 nm. A significant portion of total gas in place appears to be associated with interconnected large nanopores within the organic material. Thermodynamics (phase behavior) of fluids in these pores is quite different; gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a different density profile. This raises serious questions related to gas-in-place calculations: Under reservoir conditions, what fraction of the pore volume of the organic material can be considered available as free gas, and what fraction is taken up by the adsorbed phase? How accurately is the shale-gas storage capacity estimated using the conventional volumetric methods? And finally, do average densities exist for the free and the adsorbed phases? We combine the Langmuir adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the pore space taken up by the sorbed phase. The method yields a total-gas-in-place prediction. Molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature predict density profiles across the pores and show that (a) the adsorbed methane forms a 0.38-nm monolayer phase and (b) the adsorbed-phase density is 1.8–2.5 times larger than that of bulk methane. These findings could be a more important consideration with larger hydrocarbons and suggest that a significant adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, calculations show a 10–25% decrease in total gas-storage capacity compared with that using the conventional approach. The role of sorbed gas is more important than previously thought. The new methodology is recommended for estimating shale gas in place.

A Multi-Parameter Optimization Model for the Evaluation of Shale Gas Recovery Enhancement

“…The commercial development of shale gas has been driven by three key advances in technology and science: (1) horizontal well plus multi-stage hydraulic fracturing [1][2][3][4][5][6], (2) the understanding of gas storage mechanisms [1], and (3) the understanding of multi-scale mechanisms of gas flows from shale matrix to hydraulic fracture [7][8][9][10]. A shale gas reservoir has free gas stored in matrix pores and natural fractures, and adsorbed gas on the organic matter [11,12].…”

Geological models of gas in place of the Longmaxi shale in Southeast Chongqing, South China

“…Currently, it is difficult to evaluate the gas potential of the Longmaxi shale in Southeast Chongqing, especially in its eastern area, due to the lack of studies on GIP ). Shale gas is stored mainly as free gas and adsorbed gas, and dissolved gas can be neglected for overmature shales where liquid hydrocarbons are only in trace amount (Curtis, 2002;Montgomery et al, 2005;Jarvie et al, 2007;Jarvie, 2012;Ambrose et al, 2012). Therefore, free and adsorbed gas contents are crucial for the evaluation of GIP.…”

A Study on Geological Characteristics of Marine Shale Gas Reservoir in Southern China

“…The water saturation of any commercialized shale in North American would be quite low, which is only between 15% and 35% on average ( Fig. 1; Ambrose et al, 2012;Clarkson and Bustin, 1999).…”