Overmature Shale Gas Storage Capacity Evaluation

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.

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Models of shale gas storage capacity during burial and uplift: Application to Wufeng-Longmaxi shales in the Fuling shale gas field

Marine and Petroleum Geology ◽

10.1016/j.marpetgeo.2019.06.012 ◽

2019 ◽

Vol 109 ◽

pp. 233-244 ◽

Cited By ~ 6

Author(s):

Sile Wei ◽

Sheng He ◽

Zhejun Pan ◽

Xiaowen Guo ◽

Rui Yang ◽

...

Keyword(s):

Shale Gas ◽

Storage Capacity ◽

Gas Storage ◽

Gas Field

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Pore Characterization of the Marcellus Shale by Nitrogen Adsorption and Prediction of Its Gas Storage Capacity

Interpretation ◽

10.1190/int-2021-0019.1 ◽

2021 ◽

pp. 1-59

Author(s):

Yixuan Zhu ◽

Timothy Carr ◽

Zhongmin Zhang ◽

Liaosha Song

Keyword(s):

Shale Gas ◽

Storage Capacity ◽

Marcellus Shale ◽

Nitrogen Adsorption ◽

Well Logging ◽

Gas Storage ◽

Micropore Volume ◽

Organic Content ◽

Type I ◽

Pore Characterization

In a shale gas reservoir, pore characterization is an important factor to determine gas storage capacity. However, the nanometer (nm) scale pore system in shale is difficult to explore by traditional optical, scanning electron microscopy (SEM) or even nuclear magnetic resonance (NMR) well logging. We investigated the pore structure and storage capacity of the Marcellus Shale through integration of petrophysical analysis from lab and well logging data, and nitrogen adsorption. The isotherm of Marcellus Shale is a composite isotherm, which has features of Type I, Type II and Type IV isotherms with Type H4 of hysteresis loop, suggesting slit-like pores developed in the Marcellus Shale. Quantitative analysis of pore volumes from the nitrogen adsorption indicates that density porosity may be more proper to approximate shale porosity and estimating the shale gas volume. In addition, the specific surface area, micropore and mesopore volumes have positive relationship with kerogen volume and total organic content (TOC). By employing Langmuir and Brunauer-Emmet-Teller (BET) models, simulated result indicates that higher adsorbed quantity of the Marcellus Shale could be the result of increase of micropore volume contributed, by increase of kerogen or TOC content. The proposed equations rapidly compute TOC, a key parameter to predict gas storage capacity in over-matured shale such as the Marcellus Shale.

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