Elsevier

Organic Geochemistry

Volume 47, June 2012, Pages 120-131
Organic Geochemistry

Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems

https://doi.org/10.1016/j.orggeochem.2012.03.012Get rights and content

Abstract

A series of methane (CH4) adsorption experiments on bulk organic rich shales and their isolated kerogens were conducted at 35 °C, 50 °C and 65 °C and CH4 pressure of up to 15 MPa under dry conditions. Samples from the Eocene Green River Formation, Devonian–Mississippian Woodford Shale and Upper Cretaceous Cameo coal were studied to examine how differences in organic matter type affect natural gas adsorption. Vitrinite reflectance values of these samples ranged from 0.56–0.58 %Ro. In addition, thermal maturity effects were determined on three Mississippian Barnett Shale samples with measured vitrinite reflectance values of 0.58, 0.81 and 2.01 %Ro.

For all bulk and isolated kerogen samples, the total amount of methane adsorbed was directly proportional to the total organic carbon (TOC) content of the sample and the average maximum amount of gas sorption was 1.36 mmol of methane per gram of TOC. These results indicate that sorption on organic matter plays a critical role in shale-gas storage. Under the experimental conditions, differences in thermal maturity showed no significant effect on the total amount of gas sorbed. Experimental sorption isotherms could be fitted with good accuracy by the Langmuir function by adjusting the Langmuir pressure (PL) and maximum sorption capacity (Γmax). The lowest maturity sample (%Ro = 0.56) displayed a Langmuir pressure (PL) of 5.15 MPa, significantly larger than the 2.33 MPa observed for the highest maturity (%Ro > 2.01) sample at 50 °C.

The value of the Langmuir pressure (PL) changes with kerogen type in the following sequence: type I > type II > type III. The thermodynamic parameters of CH4 adsorption on organic rich shales were determined based on the experimental CH4 isotherms. For the adsorption of CH4 on organic rich shales and their isolated kerogen, the heat of adsorption (q) and the standard entropy (Δs0) range from 7.3–28.0 kJ/mol and from −36.2 to −92.2 J/mol/K, respectively.

Highlights

► Organic matter is the key element to control gas adsorption in shales. ► TOC is a primary control on gas adsorption capacity. ► Organic-matter type and thermal maturity affect gas-sorption rate. ► The presence of moisture can greatly reduce gas-sorption capacity. ► Quantitative model prediction is developed for adsorbed gas estimate.

Introduction

Organic rich shales have received renewed research focus the past few years because of their emergence as hydrocarbon reservoirs (Montgomery et al., 2005, Loucks and Ruppel, 2007, Rowe et al., 2008, Ruppel and Loucks, 2008). Research on mudrock attributes has increased dramatically since shale-gas systems have become commercial hydrocarbon production targets (Jarvie et al., 2007, Rowe et al., 2008, Loucks et al., 2009). Shale gases are unconventional gas systems in which the shale is both the source of, and the reservoir for, methane, which is derived from the organic matter within the shale through biogenic and/or thermogenic processes (Hill et al., 2007, Strapoc et al., 2010). Natural gas stored in shale-gas reservoirs is thought to exist in one of three forms: (1) free gas in pores and fractures, (2) sorbed gas in organic matter and on inorganic minerals, and (3) dissolved gas in oil and water. Understanding the relative proportions of gas stored in these different forms is critical to an accurate assessment of shale-gas resources and design of effective production strategies.

Gas-in-place (GIP) is crucial to shale-gas resource assessment, but estimation of gas volumes in shales is difficult (Ambrose et al., 2010). GIP is controlled by gas generation, gas preservation and rock petrophysical properties (porosity and permeability). Most pores in some shales are located in organic matter, whereas in other shale pores are largely associated with mineral grains (Reed and Loucks, 2007, Loucks et al., 2009, Sondergeld et al., 2010). The presence of organic matter in shales lowers density, increases porosity, provides the source of gas, imparts anisotropy, alters wettability and facilitates adsorption. Recent work on siliceous mudstones from the Mississippian Barnett Shale of the Fort Worth Basin, Texas, shows that the pores in these rocks are dominantly nanopores, ranging from 5–750 nm and most pores are in grains of organic matter as intraparticle pores, with a median nanopore size of approximately 100 nm (Loucks et al., 2009; Milliken et al., 2012). Reported porosity of kerogen with SEM images is around 20–25% at a thermal maturity of about 1.6 %Ro (Loucks et al., 2009, Wang and Reed, 2009) and reported porosity of kerogen by Sondergeld et al. (2010) reaches as high as 50%. Significant GIP appears to be associated with interconnected large nanopores within the organic material (Ambrose et al., 2010, Ambrose et al., 2011). The finely dispersed, porous organic material (kerogen) in shales plays an important role in gas storage.

A strong positive correlation between total organic carbon (TOC) and total gas content from the canister desorption of fresh cores in Owen and Pike Counties, Indiana (Devonian–Mississippian New Albany Shale, eastern Illinois Basin), shows that organic matter content is primarily responsible for total GIP in the New Albany Shale (Strapoc et al., 2010). A general positive correlation of CH4 sorption capacity with TOC in shales has been observed in previous studies (Lu et al., 1995, Ross and Bustin, 2007, Cui et al., 2009). Methane sorption in Devonian–Mississippian shales in the Western Canada Sedimentary Basin (WCSB) linearly increases with TOC and micropore volume (micropore refers to <2 nm pores characterized by low pressure CO2 adsorption analysis), indicating that microporosity associated with the organic fraction is a primary control on CH4 sorption (Ross and Bustin, 2009). However, thermally immature Jurassic shales in the WCSB are organically richer than Devonian–Mississippian shales, even though they have lower gas sorption capacity because of low micropore volumes and surfaces (Ross and Bustin, 2009). Microporosity, which is positively correlated with TOC in shales (Chalmers and Bustin, 2007a, Chalmers and Bustin, 2007b), is a critical component of porous media owing to large internal surface areas and greater adsorption energies of <2 nm pores compared with that of larger pores of solids with similar compositions (Dubinin, 1975, Chalmers and Bustin, 2007a, Chalmers and Bustin, 2007b, Ross and Bustin, 2009). Thermally mature shales have larger micropore volume; therefore, the ratio of gas sorption capacity to TOC content is greater in thermally mature Devonian–Mississippian shales than in immature ones. Both TOC concentration and maceral composition are important when assessing methane adsorption capacity. Shales from the Lower Cretaceous Fort St. John Group of northeastern British Columbia have high methane capacities, corresponding to either high contents of inertodetrinite or vitrinite (Crosdale et al., 1998, Chalmers and Bustin, 2007a, Chalmers and Bustin, 2007b).

The increase in sorption capacity with increase in TOC and decrease in moisture content shows that the water molecule is sorbing to specific hydrophilic sites and that other available sorption sites are taken by the methane molecule. Consideration must also be given to the hydrophilic nature of clay minerals, which reduces gas adsorption capacity and the hydrophobic nature of organic matter, which provides available sites for gas adsorption in the presence of moisture (Ross and Bustin, 2009). Under moisture equilibrated conditions, moisture may render many microporous sorption sites unavailable to CH4 by filling pore throats or occupying sorption sites (Joubert et al., 1974, Clarkson and Bustin, 1996, Clarkson and Bustin, 1999, Clarkson and Bustin, 2000, Bustin and Clarkson, 1998, Krooss et al., 2002, Busch et al., 2003, Ross and Bustin, 2007, Ross and Bustin, 2008, Ross and Bustin, 2009). Although the critical role of organic matter gas storage in shales is well documented and organic matter features (TOC content, type, thermal maturity), micropore structures and mineral compositions in shales greatly affect gas adsorption, details of the mechanism are not well understood. In particular, the effect of kerogen type and thermal maturity on gas sorption in shales is unclear and a quantitative model is not available to constrain these features under shale-gas reservoir pressure and temperature conditions.

In this study, a series of CH4 adsorption isotherms on kerogens and organic rich shales were conducted at 35 °C, 50 °C and 65 °C at pressures up to 15 MPa. The main objectives of the study were to (1) explain the main control(s) on gas adsorption in organic rich shale gas systems; (2) quantitatively constrain the difference in organic matter type and thermal maturity on gas adsorption; (3) develop an empirical model of gas adsorption affected by organic matter features, temperature and pressure from experimental simulation; (4) predict adsorbed gas amount under geological shale-gas reservoir conditions; and (5) validate the developed model with previously published data. The quantitative model, which is based on the Langmuir equation parameters developed in this study, can be applied to specific organic matter properties. Our experimental findings have important implications for shale-gas resource assessments and recovery technologies.

Section snippets

Samples and sample preparation

Two sets of organic rich shale samples were used in this study. Geochemical characteristics of the samples are listed in Table 1.

The first set of samples collected from outcrops includes Green River Formation (Eocene, Utah), Woodford Shale (Upper Devonian, Oklahoma) and Cameo coal (Cretaceous, Colorado), which are representative of source rocks having typical type I, type II and type III kerogen, respectively. The calculated vitrinite reflectance values for these three samples, based on

CH4 adsorption on isolated kerogens at 35 °C, 50 °C and 65 °C

CH4 adsorption isotherms were measured on the three kerogen samples at 35 °C, 50 °C and 65 °C under a CH4 equilibrium pressure of up to 15 MPa. The CH4 sorption capacity of the kerogens at 50 °C decreased in the order: Cameo coal (type III) > Woodford kerogen (type II) > Green River kerogen (type I) (Fig. 2; Table 2, Table 3). Differences in specific surface area and different types of organic matter can result in variation of CH4 sorption capacity, which is clearly a function of temperature and

Effect of organic matter type on gas adsorption

The Langmuir constant is related to the affinity of a gas for a surface (i.e., larger values indicate stronger affinity of the gas for the sorbent). For the samples examined in this study, the value of the Langmuir constant varies directly with kerogen type: type I kerogens exhibit the lowest Langmuir constants and type III kerogens exhibit the highest (Fig. 7a). These results indicate that differences in the chemical structure of organic matter play an important role in CH4 adsorption in

Conclusions

Our studies of CH4 sorption characteristics of bulk samples of organic rich shales and kerogen isolated from such shales reveal important cause and effect relations between organic matter type and thermal maturity and gas adsorption. Significant conclusions are as follows: Organic matter is a primary control on gas adsorption in shale-gas systems: generally, the higher the TOC content, the greater the gas-sorption capacity. Differences in organic matter type greatly affect gas sorption rates in

Acknowledgments

This research is a part of research results of the EM/BEG unconventional reservoir project, which is financially supported by ExxonMobil, 2012CB214701, 20100559 and the Jackson School of Geosciences, The University of Texas at Austin. The construction of an in-house high temperature and pressure gas adsorption system was funded by the Jackson School of Geosciences start-up funds. The Bureau’s Mudrock Systems Research Laboratory consortium and State of Texas Advanced Resource Recovery program

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