Experimental evidence of gas densification and enhanced storage in nanoporous shales
Introduction
Effective porosity or pore volume is the only rock property required in order to estimate the capacity of a conventional reservoir rock, such as a sandstone or limestone to hold gas at a given pressure and temperature. This is because the density of gas is calculable via reasonably accurate equations of state or experiments on macroscopic free gas. However, gas behaves differently in the confined environment of nanoporous materials, displaying different phase behavior with critical properties shifted relative to macroscopic free gas (Zarragoicoechea and Kuz, 2002, 2004). Deviation from macroscopic free gas properties such a density, viscosity, compressibility, etc., has been well documented in a number of nanoporous materials (Thommes and Findenegg, 1994; Morishige et al., 1997; Saha et al., 2011; Arakcheev; Morozov, 2013; Agrawal et al., 2017). Given the nanoporous nature of shales, it is reasonable to assume that such deviations from macroscopic behavior might be observable in gas held in nanoporous shales as well. An adequate understanding of gas properties and behavior in shales is essential to accurately estimating their gas storage potential, an important factor in the commercial exploitation of shale gas reservoirs.
In addition to the presence of some macroscopic free gas, there are other physical phenomena that contribute towards the overall gas storage potential of shales. The most closely studied phenomenon that is known to enhance the storativity of gas in shales is adsorption (Lu et al., 1995; Ambrose et al., 2010; Kang et al., 2011; Etminan et al., 2014; Wang et al., 2016). Adsorption is a surface phenomenon wherein gas molecules adhere to the pore surface due to physical or chemical forces of attraction and can form a high-density layer when sufficient gas is present. The prevailing view of adsorption in shales assumes a traditional Langmuir monolayer adsorption mechanism (Heller and Zoback, 2014). However, methane adsorption measurements performed by Yu et al. (2016) on Marcellus shale samples displayed significant deviation from Langmuir monolayer adsorption in some cases. Detailed characterization of the samples was not performed, and therefore it wasn't clear why the deviation was more significant in some samples compared to others. Several authors have found adsorption in shales to be positively correlated with sample organic content (TOC) (Ross and Bustin, 2009; Gasparik et al., 2014; Bhowmik and Dutta, 2019). The understanding is that hydrocarbon gases have an affinity for organic material. However, almost all of the effort so far has focused almost exclusively on hydrocarbon gases such as methane, and on carbon dioxide. This makes it difficult to separate the effects of rock chemistry from the confinement effects of nanoporosity.
Nanoporosity in shales can enhance their gas storage due to effects of pore topology on fluids, such as capillary condensation (Barsotti et al., 2016, 2018a,b), induced supercriticality (Luo et al., 2016a,b) or other alterations of gas phase behavior (Islam et al., 2015). Theoretical modeling studies show that different pore size distributions in shales can result in different expected fluid properties (Didar and Akkutlu 2013; Perez and Devegowda, 2017; Kamari et al., 2018). Experimental work to confirm these models has mostly been performed on nanoporous surrogates for shale. For instance, Barsotti et al. (2018b) performed hydrocarbon gas adsorption and capillary condensation measurements in MCM41 samples, while Luo et al., 2016a performed differential scanning calorimetry (DSC) experiments on mesoporous controlled pore diameter glasses (CPG) and MCM41. These efforts provide precise data on fluid behavior in confined environments. However, they are highly idealized systems with very narrow pore size distributions that are not very representative of the broad pore size distribution observed in shales that includes micro, meso and macro porosity. Recent work by Luo et al. (2019) is an attempt to remedy this, by creating mixtures of multiple nanoporous silicates in order to mimic the pore size distribution observed in Eagleford and Bakken shales.
There is a dearth of experimental data on gas storage in shales that evaluates a diverse set of gases and where rock characterization is performed in order to provide deeper insight into the underlying storage mechanisms. In this research study, we study the storage characteristics of hydrocarbon and noble gases in samples from four different shales. Gas storativity is measured through porosimetry experiments and density of injected gas is estimated from this data. CT imaging is also perfomed on a Marcellus sample with radio-opaque xenon gas in order to observe spatial distribution of gas as well as obtain independent supplementary data on gas density in a nanoporous sample. Sample characterization including surface area estimation from N2-low pressure surface adsorption measurements (LPSA), pore size distribution (PSD) from scanning electron microscopy (SEM) imaging, and compositional measurements are also performed in order to identify potential connections between observed gas storage behavior and rock properties that are not measured during most routine petrophysical analysis.
Section snippets
Materials and methods
Well cores from four different shales were available for this study; 12 mm diameter cylindrical core plugs were derived from the available cores. The physical properties of each of the cylindrical plugs derived from the cores is given in Table 1. The expected porosity and permeability ranges were given to us by the sponsors of the different cores. Plugs 1–4 were used in gas porosimetry experiments described in section 2.1, while plug 5 was used in the X-ray CT experiment described in section 2.2
Results
Fig. 2 shows the porosity measured on each of the four samples using helium, methane and argon gases. The helium porosity estimates are between 5% and 16.4% and are within the expected range of porosity for every sample as indicated in Table 1. However, porosity derived using methane and argon are far higher, particularly in the case of the Marcellus and Haynesville samples. In absolute terms, the methane porosities of 43.7% and 35.5% and argon porosities of 43.5% and 27.8%, in the Marcellus
Discussion
The results of gas uptake in this study of four different shales indicate that gas once taken up by shales can become denser than the surrounding free gas despite being at pressure and temperature equilibrium. The foremost explanation of this behavior is gas adsorption. The standard method of estimating adsorbed gas volumes starts with the assumption that any gas that is not in free phase, is in adsorbed phase. Helium is assumed to be non-sorbing and as such, the moles of free gas can be
Conclusions
In this study, we use the principles of gas porosimetry to measure the storage capacity of four different types of shales using noble and hydrocarbon gases. Results indicate that the storage capacities for all gases are much higher than the storage capacity of helium. This analysis indicates that gas becomes more dense by between 10% and 2750% once taken up by a shale sample. The densification behavior is observed to be similar for the hydrocarbon gas – methane, and the noble gas – argon.
CRediT authorship contribution statement
Nirjhor Chakraborty: Writing - original draft, Conceptualization, Methodology, Formal analysis, Investigation. Zuleima Karpyn: Supervision, Writing - review & editing, Conceptualization, Methodology, Funding acquisition, Resources. Shimin Liu: Writing - review & editing, Methodology, Resources. Hongkyu Yoon: Funding acquisition, Conceptualization, Writing - review & editing. Thomas Dewers: Funding acquisition, Conceptualization.
Acknowledgements
This work received funding support from the U.S. Department of Energy, the Office of Science, Basic Energy Sciences program under Award Number DE-SC0006883. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia, LLC., a wholly owned subsidiary of Honeywell International, Inc., for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-NA-0003525. This paper describes objective
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2021, FuelCitation Excerpt :The mathematical formulation presented in Eqs. (8)–(12) was solved using a finite-element numerical simulator (COMSOL Multiphysics®). Here we briefly summarize the experimental setup and procedure as further details can be found in Chakraborty et al. [10]. Fig. 3 shows a schematic of the experimental setup (Fig. 3a) as well as the actual setup (Fig. 3b).