Idealized Shale Sorption Isotherm Measurements To Determine Pore

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Idealized Shale Sorption Isotherm Measurements to Determine Pore Capacity, Pore Size Distribution, and Surface Area Randall T. Holmes, Hamza Aljamaan, Vikram Vishal, Jennifer Wilcox, and Anthony R Kovscek Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02726 • Publication Date (Web): 02 Jan 2019 Downloaded from http://pubs.acs.org on January 16, 2019

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Title: Idealized Shale Sorption Isotherm Measurements to Determine Pore Capacity, Pore Size Distribution, and Surface Area Authors: 1*R.

Holmes, 2*H. Aljamaan, 3V. Vishal, 4J. Wilcox, and 2A.R. Kovscek

Affiliations: 1Emmett

Interdisciplinary Program in Environment and Resources, Stanford University,

Stanford, CA 94305-2220, USA 2Department

of Energy Resources Engineering, Stanford University, Stanford, CA 94305-

2220, USA 3Department

of Earth Sciences, Indian Institute of Technology Bombay, Powai, Mumbai,

400076, India 4Chemical

and Biological Engineering Department, Colorado School of Mines, Golden, CO

80401, USA *Denotes equal contribution. Corresponding Author: Anthony R. Kovscek, Kellen and Carlton Beal Professor Stanford University Department of Energy Resources Engineering 367 Panama Street Green Earth Sciences 074 Stanford, CA 94305-2220 E: [email protected]

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Abstract One potential method for mitigating the impacts of anthropogenic CO2-related climate change is the sequestration of CO2 in depleted geological gas and oil formations, including shale. The accurate characterization of the heterogeneous material properties of shale, including pore capacity, surface area, pore-size distributions (PSDs), and composition is needed to understand the potential storage capacities of shale formations. Powdered idealized shale samples were created to explore reduction of the complications in characterization of pore capacity that arise from the heterogeneous rock composition and pore sizes ranging over multiple orders of magnitude. The idealized shales were created by mechanically mixing incremental amounts of four essential powdered components by weight and characterized with low pressure gas adsorption/desorption isotherms (LPGA). The first two components, organic carbon and phyllosilicates (such as clays, micas, and chlorite), have been shown to be the most important components for CO2 uptake in shales. Organic carbon was represented by kerogen isolated from a Silurian shale, and phyllosilicate groups were represented by powdered illite from the Green River shale formation. The remainder of the idealized shale was composed of equal parts by weight of SiO2 to represent quartz and CaCO3 to represent carbonate components. Three idealized sample groups were prepared to be approximately 10, 30, and 55 percent illite by weight. Each of the sample groups consisted of four samples, incrementing the percent kerogen from 1.5 to 6 percent. Eagle Ford, Baltic, and Barnett shale sorption measurements were used to validate the idealized sample methodology. The sorption isotherms were measured volumetrically using low pressure N2 (77K) and Ar (87K) adsorbates on a Quantachrome Autosorb IQ2. Both idealized and validation samples were outgassed using a standardized procedure that produced repeatable results while minimizing changes to the material properties of the shale. The idealized sample results indicated a positive linear correlation with increasing TOC and pore capacity. This work is essential toward the development of predictive models weighted and scaled by the corresponding mineral compositional description of the reservoir. Keywords: Shale, Pore Size Distribution, CO2 storage, Low Pressure Gas Adsorption.

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1. Introduction With recent development of shale geological formations as a source of hydrocarbons, research and development regarding these resources have accelerated at an unprecedented pace. The focus has been on determining estimates of the gas-in-place, easing gas extraction, and the overall integrity of the reservoir system during and after extraction. With the recent quest for finding shales as suitable CO2 storage sites, a new domain of investigation has opened (Elliot and Celia, 2012; Carroll et al; 2013). The key reservoir properties such as rock composition, porosity, pore capacity (i.e., the total mass of a chemical species retained by shale), permeability and strength have been determined for many of the prospective shale systems. The results of measuring these properties have made it apparent that the compositions of shales vary from basin to basin, strata to strata, within the same strata, and even from opposite sides of the same core. Attempts to correlate these properties are challenging given the heterogeneous nature of shale on at least two fronts. First, the physical composition of shales includes numerous components in the rock at various ratios and stages of geochemical and/or thermal maturity. Second, pore sizes in shales can span multiple orders of magnitude, from visible millimeter fractures all the way down to the nanoscale width of individual gas molecules. These issues can begin to be resolved by understanding the fundamental physical properties and mechanics at various discrete scales across the strata or basin. To address the first issue, this study reduces the number of essential components under consideration to just four: kerogen, illite, silica, and calcium carbonate. The highest purity powdered components available were used, such as lab grade silica and calcium carbonate, well-characterized illite, and a kerogen isolate. To address the second, this study focuses on a specific size range that may later be incorporated into a separate pore-size study rather than span all of the length scales of the pore sizes found in shale. The scale here is chosen because it represents a pore-size range important for shale gas storage. Larger pore sizes are left for analysis using other methods and accounting for processes associated with free gas and permeable pathways.

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It is important to recognize that gases stored in nanoscale pores may be adsorbed or may be tightly packed dissolved species. Hence, a greater volume of gas is stored than is suggested from a simple volumetric measurement that accounts for only free gas in pore space. As such, the term pore capacity is used here rather than the term pore volume to account for all gas within the porous medium. The analysis of pore capacity and pore-size distributions for both individual components and natural shale samples is also challenged by inconsistent sample preparation across the literature. As a matter of new protocol proposed by Aljamaan et al., 2017 and Holmes et al., 2017, the idealized and validation shale samples were outgassed at 250°C and the sorption isotherms measured using low pressure N2 (77K) and Ar (87K) adsorbates on a Quantachrome Autosorb IQ2. Quantachrome’s quenched solid density functional theory data reduction software was used for the pore size distributions (PSD), pore capacities, and specific surface areas. Thermogravimetric analyses were conducted separately to inform the relative mass loss at different temperatures of kerogen and illite. The thermogravimetric method was not used for measuring or analyzing pore capacities. The scale in the current study focuses on pore capacities that result from pore sizes of approximately 1-27 nm. The 27-nm cutoff is approximately the midpoint of IUPAC mesopores, that are defined as pore widths or diameters of 2-50 nm whereas micropores are pore widths or diameters of < 2.0 nm. The results of the current study also include a small (< 0.1%) amount of the measured pore capacity attributed to larger micropores (1.0-2.0 nm); however, this should not be considered a robust micropore measurement or analysis because low pressure adsorption in shales using the low temperatures required for N2 (77K) and Ar (87K) has limitations arising from kinetics and tortuosity of the shale. As this is an exploratory study to determine the usefulness of idealized shale, the analysis of micropores using a CO2 adsorbate was not conducted. Because surface area can increase by orders of magnitude in the micropores, the analysis of surface area without micropore measurements would be incomplete and less than robust. As such, this study focuses on pore capacities arising from the 1-27nm span. The surface area analysis was left to future work that includes a thorough micropore analysis. 4 ACS Paragon Plus Environment

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There is debate about the mechanisms underlying correlations between pore capacities and variables such as total organic carbon (TOC), phyllosilicate content (specifically clays), and thermal maturity and/or depth of reservoir (Rexer et al., 2014). The intuitive hypothesis is that in all cases, the pore capacity of any particular shale sample should be a simple sum (e.g. a weighted superposition) of the pore capacity of its relative components; however, this has proven to be problematic and nontrivial when attempting to use data in existing literature that alternately shows positive correlations for TOC in the case of Ross and Bustin (2009), versus no correlation in high TOC shales, as shown in Gasparik et al. (2012). Kuila et al. further the investigation on pore capacity correlations with variables such as total organic carbon content, phyllosilicate content (specifically clays), and thermal maturity and/or depth of reservoir (2014). The correlational results are not always consistent or statistically significant. Nevertheless, the kerogen and clay components of shale have been shown to be the essential components for pore capacity in smaller mesopores and micropores (Ross and Bustin, 2009; Jin and Firoozabadi, 2014; Fan et al., 2014; Heller and Zoback; 2014, Lu et al., 1995), which are considered the main source of methane and possible eventual sinks for sequestered CO2. The composition of kerogen and types of clays also control the ultimate gas storage capacity in shales. For instance, organic matter such as kerogen, which is measured and reported here as TOC, is correlated with the porosity, gas content, pore size distributions, and even geomechanical parameters (Loucks et al., 2009; Liu and Wilcox, 2011; Heller et al., 2014; Vishal et al., 2015; Aljamaan et al., 2017). Fan et al. (2014) established that the methane adsorption capacity of phyllosilicate minerals decreased in the order: montmorillonite > kaolinite > illite > illite/smectite mixed layer > chlorite. This study uses the more general term of phyllosilicates when referring to clays to ensure inclusion of components that are not 2:1 clays, but were still found to be present during the XRD analysis of the validation samples. The phyllosilicates will be abbreviated as CMC for clays, micas, and chlorite. Literature shows that adsorption capacity studies have either been carried out on individual components or on representative shale samples. The

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treatment of both individual shale components alongside individual heterogeneous shale samples in this paper unifies the separate approaches. This study tests the hypothesis that, despite the heterogeneity of shales, the pore capacities of shales should be the sum of the pore capacities of the relative components. We develop a methodology to mix the purest available powdered components of shale in the desired proportion to provide the best representative composition for the chosen reservoir. These ‘synthetic’ or ‘idealized’ powdered shales have known concentrations of all four key components: kerogen, phyllosilicates, silica, and calcium carbonates. Secondly, this study attempts to confirm the credibility of using such idealized shales by comparing their pore capacities to real shales. This is a proof of concept study to lay the groundwork for future studies that explore the possibilities of the predictive power and scientific utility of such idealized shales if they are shown to not only confirm the hypothesis, but also represent the pore capacities of real shale at the 1-27 nm scale. Subsequent studies could then follow in order to explore and explain the possible phenomenon that underlie the variation in shale pore capacities when their pore capacities do not appear to reflect the sum of the parts, such as the role of thermal maturity, compaction, the micron-scale arrangement of minerals, and so on.

2. Experimental This section describes preparation of both the idealized and validation samples followed by an explanation of the low pressure adsorption experiment. 2.1 Sample Meshing A standard for the degree to which shale must be crushed has not been established in the literature. As long as the crushed particles are sufficiently small to eliminate the problems of low permeability, it should suffice. Some groups report crushing shale and sieving at 40 mesh ( 3250

18.6

22.4

1.8

56.0

2.17

Baltic 12

> 4409

43.8

1.3

3.2

51.5

0.54

Baltic 13

< 4409

24.9

26.0

1.8

48.0

0.22

Baltic 14

4409

34.1

1.6

0.91

62.8

1.70

Baltic 15

> 4375

37.4

0.62

2.2

58.3

1.63

* Reproduced with permission (Holmes et al. 2017, Psarras et al. 2017). ϯ Clays, micas, chlorite (CMC).

2.4 X-ray diffraction Semi-quantitative X-ray diffraction (XRD) was used to obtain approximate compositions of the raw illite, idealized series, Barnett, Eagle Ford, and Baltic samples. X-ray diffractograms

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were collected using a Rigaku Miniflex 600. The diffractograms were analyzed using the PDXL2 software. 2.5 Low-Pressure Gas Adsorption Analysis Low pressure gas adsorption isotherms were measured using an Autosorb iQ2 (Quantachrome Instruments) and interpreted from the adsorption branch using the quenched solid density functional theory (QSDFT) model, assuming a carbon adsorbent and cylindrical pores (Lowell et al. 2004) for the estimates of pore capacities found in Table 3. The carbon adsorbent is chosen because of the propensity for gas adsorption to favor the kerogen of shales, as well as to have consistent comparisons between validation samples and the idealized shales. The carbon adsorbent model was also used for all of the individual raw components in order to have the ability to compare the summation of the pore capacities of the individual components at their relative weights with the idealized and validation shales. The samples were outgassed as stated in Section 2.5.1. The QSDFT calculations were based on a 55-point adsorption branch, with measurements made on relative pressures (P/P0) spanning from 10−6 to 0.995. Each point was required to maintain an equilibration time of at least two minutes. The QSDFT model pore capacities were reported through a pore diameter of approximately 27 nm, with IUPAC defined mesopores described as 2.0-50 nm, and micropores < 2.0 nm. Pore capacities for fine mesopores and micropores (1.0-27nm) were measured with N2 (99.999%) as the adsorbate at 77 K for the Baltic and idealized samples, with the temperature held constant by a liquid nitrogen bath. The low clay group of the idealized samples, Barnett and Eagle Ford validation samples were analyzed using Ar as the adsorbate at 87 K to the extent possible, with temperature held constant in a liquid argon bath. Micropore analysis using CO2 was not conducted in this study. However, there is some overlap for both Ar and N2 into the micropore region. For instance, some samples indicated pore capacity measured in micropores in the range of 1.0-2.0 nm. The micropores that were measured accounted for 0.07% or less of the cumulative pore capacity in the 1-27 nm range for both Ar and N2 as adsorbates. As such, the pore sizes contributing to the pore capacities in this study are listed as ranging from 1.0 nm to 27nm using Ar and N2, leaving the 12 ACS Paragon Plus Environment

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micropore features of the idealized shales using CO2 as an adsorbate for another possible study. As detailed in Section 2.5.1, Ar was selected as the adsorbate for analyzing how the idealized shales compare to validation shales in response to outgassing at increasingly high temperatures. The choice of Ar as the adsorbate is supported by the IUPAC Technical Report by Thommes and Cychosz (2014). While N2 was used for the Baltic validation samples, medium, and high idealized samples, the Ar data matched closely to the N2 data on the low idealized set, and therefore, running the N2 samples on Ar was not determined to be necessary. 2.5.1 Outgassing Temperature To show the maximum possible pore capacities, all samples were outgassed at a pressure of 10-5 bar for at least 10 hours at 523 K (250 °C) using methodology previously reported Holmes et al. (2017) and Psarras et al. (2017). The 523 K (250 °C) is expected to yield the highest possible pore capacities while minimizing the structural alterations to the shale. The 250 °C outgassing temperature is hypothesized to be very close to the minimum between the S1 and S2 pyrolysis curve, as depicted in the cartoon in Figure 1 as the inter-S-curve minimum, previously referred to by Holmes et al. (2017) as the “pre-generation trough.” Select idealized and validation samples were also outgassed at multiple temperatures to compare the effects of outgassing temperature on the idealized shales as compared to the validation samples. The additional outgassing temperatures selected were at or near temperatures commonly found throughout low-pressure adsorption experimental literature: 333 K (60 °C), 383 K (110 °C), and 473 K (200 °C). The impact of increasing the outgassing temperature are reinforced by thermogravimetric analysis. The low clay idealized shales were outgassed at all four temperatures. The Barnett and Eagle Ford samples were outgassed at 60 °C and 250 °C.

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Figure 1. Cartoons of kerogen pore conditions for low pressure sorption measurements resulting from the different outgassing temperatures. The cylinders above the S curve represent pores and are situated above points on the S curve to show the hypothetical states of adsorbed or evolved gases as temperature increases. For each shale, there is a hypothetical minimum between the S1 and S2 curve where the pore is completely free of adsorbed species, and yet has not evolved any hydrocarbons from kerogen. The exact temperature for each shale minimum is not known, but should be in the inter-S-curve minimum, which is proposed to be between 200 °C and 250 °C.

2.6 Thermogravimetric Analysis In order to analyze possible impacts of the outgassing temperature on illite and kerogen components, thermogravimetric analysis was performed using TA Instrument Q500 TG. This thermogravimetric analysis should not be confused with gravimetric measurements using high pressure adsorption instruments (such as a Rubotherm) that also create isotherms that can be used to analyze pore size distributions and pore capacities. No pore capacities were produced from this thermogravimetric analysis. Samples were prepared as described in Section 2, with a sample mass of 20 mg. Each sample was run under a N2 atmosphere, with a temperature increase ramp of 10 °C/min from 30 °C to 1000 °C. Each run included a blank run on the sample crucible, followed by the sample being run in the same crucible.


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3. Results and discussion 3.1 Interpretation of PSDs Given the interest in the nanoporosity of shale, the ultimate goal of sorption isotherms is to determine pore capacities and pore-size distributions. There are a number of options for determining the pore-size distribution. Based on the limits of the traditional methods such as BJH, which can underestimate pores less than 10 nm by as much as 20-30%, DFT-based methods have been chosen for the PSD interpretation (Thommes et al., 2015). Pore characterization of shales using low-pressure adsorption must be limited to a region lower than approximately P/P0 = 0.9 as recommended in Holmes et al. (2017). P0 is held to approximately atmospheric pressure of 760 torr by the Autosorb. Hysteresis between the adsorption and desorption branches are consistent with complex pore networks, and the closing of the hysteresis loops only at very low pressure, with both N2 and Ar, is another indicator of complex pore networks, as detailed by Lowell et al. (2004). The dropoff observed in the desorption branch around the relative pressure of 0.4-0.5 is a result of metastability issues with the adsorbates as discussed elsewhere (Holmes et al, 2017; Lowell et al 2004), and as such, the trends illustrated in this paper make pore capacity comparisons using the adsorption branch with a maximum pore diameter cutoff of approximately 27 nm for both Ar and N2. This diameter is the maximum pore diameter cutoff available from the Quantachrome quenched solid density functional theory using cylindrical pores on a carbon adsorbent. The Quantachrome model allows N2 through 33 nm on carbon, but for consistency, the N2 on carbon values were also reported only through 27 nm in the tables. Representative adsorption/desorption isotherms can be referred to in Figure 2.

3.2 Raw components PSD and adsorption capacity The four main components have cumulative pore capacities that increase as CaCO3/pyrite/barite < SiO2 < illite < Silurian kerogen. Additional trace amounts (i.e., less than 3%) of barite and pyrite can also be found in some shales, but were found to have pore capacities similar to CaCO3. As the relative amount of barite and pyrite are small compared to the other four components, little pore capacity should be attributed to barite and pyrite in these samples. Most of the pore capacity will be found associated with kerogen and illite. The

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isotherms and PSDs for the four main components, as well as barite and pyrite, are shown in Figure 2 and Figure 3, respectively. Notice the change of y-axis scale for each subplot.

Figure 2. Low pressure adsorption measurements using Ar on illite and kerogen, and N2 on raw components. Kerogen shows the greatest adsorption capacity followed by illite. Adsorption filled symbol. Desorption unfilled symbol. Barite -o- Pyrite -Δ- CaCO3 -⧠-


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4

10 0

0

2

5

10

15 20 Pore Width (nm)

25

30

Pyrite, Barite, and CaCO3 N2

2

0 35

0.4

1.5

0.3

1

0.2

0.5

0.1

0

0

5

10


25

30

0 35

18

150

15

120

12

90

9

60

6

30

3

0

0

5

10


25

30

SiO2 N2

20

0 35

2

15

1.5

10

1

5

0.5

0

0

5

10


dV(d) (cc/nm/g) *10-3

20

Silurian Kerogen Ar

180

25

30

dV(d) (cc/nm/g) *10-3

6

Cumulative Pore Volume (cc/g) *10-3

30

dV(d) (cc/nm/g) *10-3

8

Cumulative Pore Capacity (cc/g) *10-3

Illite N2

40

dV(d) (cc/nm/g) *10-3

Cumulative Pore Capacity (cc/g) *10-3

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Cumulative Pore Volume (cc/g) *10-3

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0 35

Figure 3. Low pressure adsorption measurements using Ar on illite and kerogen are plotted through 27 nm, and plotted through 33 nm for additional raw components using N2. Kerogen shows the greatest adsorption capacity followed by illite. Cumulative pore capacity filled symbol. Pore-size distribution unfilled symbol. Barite -o- Pyrite -Δ- CaCO3 -⧠Table 3: Idealized raw components pore capacities outgassed at 250 °C outgassed using Ar or N2 as labeled. Barite and pyrite were outgassed at 50 °C. Mean Pore Capacity (cc/g) 1.0-27 nm 0.222

Min Pore Capacity (cc/g) 1.0 - 27 nm 0.178

Max Pore Capacity Max (cc/g) 1.0 - 27 nm 0.249

Kerogen*

Adsorbate Ar

Illite (%) 0.0

TOC (%) 74.4

Mean Pore Capacity (cc/g) 1.0-15 nm 0.140

DFT Surface Area (cm2/g) 1.0–27 nm 121.1

Illite*

Ar

96.0

0

0.019

0.030

Silica

N2

-

-

0.005

0.011

-

-

4.3

Carbonate

N2

-

-

0.001

0.002

-

-

0.7

Pyrite

N2

-

-

< 0.001

0.001

-

-

0.5

Barite

N2

-

-

< 0.001

0.002

18.3

0.4

*Average of three kerogen samples and four illite samples. 3.3 Impact of varying TOC and illite content on idealized samples The primary factor for determining pore capacity in the idealized and validation shales is the TOC, followed by clay. When grouping the idealized shales together by constant TOC, each of the idealized shale sets show increasing pore capacity with increased illite content, as shown 17


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in Figure 4 and Figure 5. The 1.5% TOC group has some overlap between the high clay and medium clay groups. This could be the result of the variations in pore size distribution inherent to the kerogen, and gives cause to conduct experiments at additional pore scales, especially the larger mesopores. For instance, 25-50 nm would be appropriate drawing from this data. All four of the TOC groups show the groups with small amounts of clay have the least amount of pore capacity, however the medium and high clay groups have some overlaps. The 4.5% TOC group shows an increase in pore capacity from low, to medium, to high clay content across the pore sizes shown. The 3.0%, and 6.0% TOC groups show the medium clay having slightly more pore capacity in smaller pore diameters (

Idealized Shale Sorption Isotherm Measurements To Determine Pore

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