High-Pressure Methane Sorption on Dry and Moisture-Equilibrated

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High-Pressure Methane Sorption on Dry and Moisture-Equilibrated Shales Feng Yang, Congjiao Xie, Zhengfu Ning, and Bernhard M. Krooss Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b02999 • Publication Date (Web): 13 Dec 2016 Downloaded from http://pubs.acs.org on December 18, 2016

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Energy & Fuels

High-Pressure Methane Sorption on Dry and Moisture-Equilibrated Shales Feng Yang a,b,*, Congjiao Xie a, Zhengfu Ning b, Bernhard M. Krooss c

a

Key Laboratory of Tectonics and Petroleum Resources (China University of Geosciences), Ministry of

Education, Wuhan 430074, PR China b

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing),

#18, Fuxue Rd, Changping, Beijing 102249, PR China c

Energy and Mineral Resources Group (EMR), Institute of Geology and Geochemistry of Petroleum and

Coal, Lochnerstr. 4-20, RWTH Aachen University, 52056 Aachen, Germany

* Corresponding Author: [email protected]

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ACS Paragon Plus Environment

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ABSTRACT: High-pressure methane sorption isotherms were collected on selected Paleozoic shales

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from Sichuan Basin. Excess sorption measurements were performed on shales with varied water content

3

(dry, moisture equilibrated at 33, 53, 75, and 97% relative humidities) at 39 °C and up to 25 MPa. Water

4

uptake isotherms were collected at 24 °C and parameterized by the Guggenheim-Anderson-de Boer

5

(GAB) model. The effect of organic richness, mineral compositions, and pore structure characteristics on

6

water uptake and methane sorption behavior has been investigated. The mechanism responsible for the

7

decrease in methane sorption capacity of moisture-equilibrated shales is discussed.

8

Water uptake of shales is primarily controlled by clay minerals, and shows a positive correlation with

9

clay mineral content. Water sorption isotherms of shales can be approximately expressed as the sum of

10

the isotherms of individual clay minerals on a mass-fraction base. Methane sorption capacity of these

11

shales is controlled by TOC content. The maximum Langmuir sorption capacity of shales under both dry

12

and 97% RH conditions correlates positively with TOC content. Compared to dry condition, methane

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sorption capacity of shales moisture-equilibrated at 97% RH is reduced by 44 to 63%. The experimental

14

results indicate a step-wise decline in methane sorption with increasing water content. Evolution of

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sorption capacity as a function of water content can be divided into three stages: (1) initial decline stage:

16

the decrease of methane sorption capacity is mainly due to competitive sorption of methane and water

17

on hydrophilic clay minerals. (2) steep decline stage: clusters of water molecules block pore space and

18

reduce the sorption capacity significantly. (3) slow decline stage: a contiguous water phase successively

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fills the macropores and slightly reduces methane sorption by volume displacement.

20

KEYWORDS: shale gas; methane; sorption isotherm; water sorption; Langmuir

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1. Introduction

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Advances in horizontal drilling and hydraulic fracturing have permitted to extract hydrocarbon from

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unconventional reservoirs. Shale gas and tight oil formations provided 50% of the US dry gas production

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in 2015, and the percentage is estimated to increase to 69% by 2040.1 Sorption is an important storage

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mechanism of natural gas in organic-rich shale reservoirs. More than 50% of the total gas capacity of the

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Devonian shales in the Appalachian basin2 is associated with gas sorption, and the ratio of sorbed gas to

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total stored gas is up to 70% in biogenic Antrim shales 3.

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Gas storage in unconventional shale reservoirs is a complex multi-parameter problem. Studies to

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date identify organic matter characteristics (total organic carbon (TOC) content, thermal maturation, and

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kerogen type), mineralogy, pore system, moisture, pressure and temperature as important parameters in

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assessment of gas sorption capacity of shales.4–17 Organic matter in shales has been considered as the first

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contributor to gas sorption capacity of shales. Previous studies have reported the positive correlation

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between TOC content and methane sorption on black shales of North America7 and Europe9,15. Thermal

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maturity of organic matter has positive effect on the methane sorption capacity of shales, and this is

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ascribed to the increase in the organic micropores and/or change in chemistry characteristics of organic

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matter during thermal maturation.6,7 When it comes to the type of organic matter of shales, sorption

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capacity on TOC basis was reported to increase in order: type I < type II < type III, and this was attributed

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to the larger micropore surface area of humic kerogen compared to other maceral composition when the

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organic matter is highly mature and the increasing kerogen aromaticity of organic matter in the

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progression from type I to type III kerogen.5–7 In addition to organic matter, pores of inorganic

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constituents (clay minerals) accommodate additional sorbed gas due to their developed internal surface

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area, and contribute appreciable amounts of gas sorption in clay-rich shales under dry condition. 8, 15, 18, 19

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Moisture is known to have a strong reducing effect on methane sorption in coals and shales. Though

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researchers realize the negative influence of water on sorption behavior of shales, many of them do not

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address the issue of water in much detail.9, 12, 13 Day et al.20 described a linear decrease in sorption

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capacity of coals up to certain critical value above which gas sorption capacity is unaffected. However,

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the interaction between natural carbonaceous materials (such as coal and shales) and water is complex

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and the mechanisms of sorption capacity reduction with moisture are not fully understood. Sorption of

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water on coal is connected with physisorption on functional groups and chemisorption onto mineral

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surfaces.21 Typically, the chemisorbed water cannot be desorbed completely under vacuum at low

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temperatures. In addition, water tends to form large clusters via hydrogen bonds and block large pores and

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interparticle voids.20, 21

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Although significant progress has been achieved in the experimental methodology and technique for

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measuring gas sorption isotherms, data on the high-pressure sorption isotherms on shales in the presence

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of moisture/water are scarce, and the role of water on gas sorption of shales is still poorly constrained.

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The present paper summarizes the experimental results of recent investigations on methane sorption

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capacity of dry and moisture-equilibrated marine shales from Sichuan Basin that are being considered as

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the main target for shale gas exploration in China. High-pressure methane sorption isotherms at 39 °C and

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pressures up to 25 MPa were determined for four Paleozoic shales at five different relative humidity

60

conditions. The main objectives of the study were to assess the sorption capacity of these shales, with

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special reference to the mechanism of the reduction of their methane sorption capacity caused by the

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presence of water. Besides, the effects of organic richness, mineral compositions, and pore structure

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characteristics on water uptake of shales are also discussed.

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2. Experimental section 4


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2.1 Samples

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Marine shales from the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi

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Formation in Sichuan Basin were collected for this experimental study (Figure 1). The Wufeng-Longmaxi

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shales in Sichuan Basin are currently considered as the main targets for shale gas exploration in China.

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Several shale gas fields operated by PetroChina and Sinopec have been developed in Sichuan Basin. One

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upper Ordovician (CN_11) and two lower Silurian shale samples (the bottom of Longmaxi Formation:

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CN_22, the top of Longmaxi Formation: CN_33) were collected from the field standard stratotype section

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in Changning area of Southern Sichuan Basin. The Wufeng Formation (CN_11) and the Lower part of

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Longmaxi Formation (CN_22) are mainly black graptolite shales, while the Upper part of Longmaxi

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Formation is mainly silty shale (CN_33). TOC content is high at the bottom of the stratotype section and

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then decreases upwards, which indicates that the sea level decreased, and the hydrodynamic force

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increased from the Late Ordovician to Late Silurian.22 The fall of sea level was unfavorable for the

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preservation of organic matter. In addition, one Lower Silurian Longmaxi Formation shale sample

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(CQ_14) from Chongqing area was also added to the sample list. General geological descriptions of the

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sedimentary environment, petrofacies, and potential evaluations of the shales in Sichuan Basin have

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recently been published.15,22–24 Results from organic geochemistry and XRD measurements of the samples

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are presented in Table 1. The samples investigated exhibit TOC values of 0.96–9.40%, with helium

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porosity values ranging between 4.4 and 13% (Table 2). The “equivalent” vitrinite reflectance (Req),

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derived from the bitumen reflectance, ranges from 2.4% to 2.8%, indicating that these samples having

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reached a very high thermal maturity.

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2.2 Pore size distribution and specific surface area

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The application of N2 physisorption analysis, originally developed for material sciences,25 has been

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addressed in shale characterization previously.26,27 Low pressure nitrogen adsorption-desorption

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measurements at 77 K (–196 °C) were conducted to quantitatively characterize the pore structure of

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shale samples. Sorption measurements on shales are commonly performed with powdered samples (60–

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100 mesh particle size). 4,6,7–9,15,18 In this study, powder samples (~100 mesh, 0.149 mm) were outgassed

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overnight at 105 °C under vacuum. The adsorption-desorption isotherms were collected on Micromeritics

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Surface Area and Pore Size Analyzer (Gemini VII 2390t). Adsorbed amounts of N2 were measured for

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each relative pressure (absolute/saturation pressure) point, and dynamic equilibrium was assumed when

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the pressure change over an interval (10 s) was < 0.01% of the average pressure in the latter interval.

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Multi-point Brunauer-Emmett-Teller (BET) analysis was used to quantify the specific surface area, and

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the Barrett-Joyner-Halenda (BJH) approach was applied to calculate pore size distributions.

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2.3 Water uptake measurements

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Water uptake as a function of water vapor pressure was determined by moisture-equilibrating the

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samples at different relative humidities (RH) at room temperature (~24 °C). Powdered samples (~100

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mesh, 0.149 mm) were first dried in a 105 °C vacuum oven overnight before determining their dry weight

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(mdry). Then the dried samples were placed in a desiccator where containing a saturated salt solution to

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establish a defined water vapour partial pressure (relative humidity, RH). Five different saturated salts

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solutions were used for humidity control: LiCl (11% RH), MgCl2 · 6H2O (33% RH), Mg(NO3)2 · 6H2O

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(53% RH), NaCl (75% RH), and K2SO4 (97% RH).28 Moisture equilibration on shale samples was carried

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out at different humidity levels until the sample weights remained constant. The moisture uptake (in g/g)

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was calculated as:

107 108

(/ ) =

(/ )

(Eq. 1)

Water sorption isotherms were obtained by plotting the water uptake against the relative pressure

6


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(p/p0). The water uptake isotherms were parameterized by the 3-parameter Guggenheim-Anderson-de

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Boer (GAB) model: 29

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(/ ) =

( )(() )

(Eq. 2)

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Here wm is the GAB monolayer capacity; aw is the sorbate (water) activity and equivalent to relative

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pressure (aw = p/p0); c and k are GAB constants, which are correlated with the heat of adsorption. The

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GAB equation has a similar form as the well-known BET equation, and reduces to the BET equation

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when k = 1. The unknown parameters in the GAB equation can be determined by fitting the measured

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data using a non-linear regression.

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2.4 High-pressure methane sorption experiments

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High-pressure sorption experiments were conducted on a manometric apparatus at 312 K (39 °C)

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and up to 25 MPa. The experimental set-up consists of a stainless steel sample cell (SC), two

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high-pressure electric-pneumatic valves and a high-precision Keller pressure transducer (PT maximum

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pressure 30 MPa with an accuracy of 0.05% at full scale value). The reference cell (RC) is the volume of

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the tubing connecting the two valves and the dead volume of the PT. Volumes of the RC and SC were

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calibrated by helium expansion using stainless steel cylinders of known dimensions placed in the SC.

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Dry/moisture-equilibrated powder samples (~100 mesh) were placed into the SC and the void volume

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(Vvoid) of the SC was determined by helium expansion. The measuring procedure starts by charging RC

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with a certain amount of methane and allowing certain time for equilibration in RC. Then methane

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expands to the SC and sorption begins. The sorption system reaches equilibrium in 1–3 h, depending on

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the moisture condition of the shale sample. Furthermore, blank methane expansion tests were performed

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on steel cylinders of different sizes placed in the SC at target temperature. The blank sorption isotherms

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of steel cylinders with different “void volumes” were interpolated to acquire the blank expansion value of

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a shale sample at an equivalent void volume. From the “raw” expansion data measured on a shale sample,

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the blank expansion value was subtracted to obtain the final corrected excess sorption isotherm. A detailed

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description about the experimental setup and measuring method has been published previously.8, 9, 30, 31

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The excess sorbed mass (mexc), also denoted “Gibbs surface excess”, is calculated according to the following mass balance:

136

=

!

− #$% (&, ())*

+,

(Eq. 3)

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Here Vvoid is the pore space that is not occupied by the powered sample in SC and determined by helium

138

expansion; mtotal is the total mass of adsorbate (methane) transferred into the SC; ρgas(T, P) is free gas

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density determined from equations of state provided by Kunz et al.32 Excess adsorbed mass was

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converted to excess adsorbed amount of substance (nexc, mmol/g). The experimental excess sorption data

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was parameterized by an adapted Langmuir function:8,9,15, 30,33 345

/

142

- = -. //

0 (1)

(1 − 3

)

(Eq. 4)

5

143

Where nL (mmol/g) is the Langmuir sorption capacity (also denoted as the Langmuir volume when

144

expressed in units of volume per mass); P (MPa) is the pressure of the free gas; PL (MPa) is the Langmuir

145

pressure; ρads (kg/m3) is the density of the adsorbed phase.

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3. Results

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3.1 Pore structure characteristics by nitrogen adsorption

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All the low-pressure nitrogen adsorption isotherms of the shales studied are of type IV (Figure 2).

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The low-pressure nitrogen adsorption isotherms of these shale samples exhibit hysteresis in terms of the

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divergence of the adsorption-desorption branches, which indicates that mesopores (2 nm < pore widths
33% for CN_22 and CQ_14. The k values obtained from the fitting procedure range

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from 0.7 to 0.9, which is in accordance with the limit values (0.24< K 53%, and shows remarkable water uptake between 75% and 97% RH. The

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intersection of water uptake isotherms at high relative pressure is probably caused by larger

247

micro-porosity (Figure 2b), hence greater amount of capillary condensate water. PSD derived from N2

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adsorption show that the micropore volume of sample CQ_14 is significantly larger than those for other

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three samples (Figure 2b). Micropores are apt to be filled by water molecules. Water molecules firstly

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sorb on primary sorption centers of clay minerals (functional groups containing oxygen). Table 4 shows

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that shale samples with higher clay mineral contents have higher relative loss in methane sorption

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capacity of shales at the initial stage of water uptake. Monolayer coverage finish when the polar sites are

253

occupied by water molecules. Then the adsorbed water molecules act as secondary sorption sites

254

(nucleation sites) for further water sorption by hydrogen bonding, which results in the formation of

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three-dimensional water clusters. Water sorption will be remarkably enhanced when the clusters of water

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molecules connect together by “bridges”.40 Eventually, pore filling will occur at high relative pressure.

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There is a positive relationship between BET surface area and water content of the 97% RH

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moisture-equilibrated samples (Figure 6c). The intercept value is about 0.01 g/g, indirectly indicating that

259

water in shales is likely to be in the form of condensed phase apart from sorbed state.

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4.2 Quantification of water uptake as related to mineralogy

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Since water sorption on shales is mostly attributed to clays, a linear combination approach is applied

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for predicting sorption isotherms of water on shales based on the mass fractions of mineral components.

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This concept has been successfully used to evaluate several rock physical parameters in our previous

264

studies.15,16 It was assumed that water sorption on framework minerals (quartz, calcite, etc.) is negligible,

265

and the water uptake of the shales is expressed as the sum of amounts of adsorbed water on individual

266

mineral components in mass fraction. Combined with the available water isotherms for typical clay

267

minerals (Figure 7a),35 the constructed water sorption isotherms of shale samples are obtained. The

268

calculated water sorption isotherms reasonably fit the measured data at most of the relative humilities

269

range, and show typical inversed S-shaped Type II isotherm (Figure 7b). This demonstrates the

270

applicability of the developed method, and indicates that the water uptake of shale samples is primarily

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associated with clay minerals. The calculated water uptake overestimates the measured value of CN_22

272

by a factor of 1.4 at 97% RH. The difference between the calculated water isotherms and the measured

273

data in high relative humidities could be attributed to the fact that the milling process may increase the

274

accessible internal surface and finely ground (< 2 µm in Martin 35) provides better accessibility to water

275

than the 150 µm particles in present study. It is also possible that the water uptake behavior of pure clay

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minerals, not constrained by the rock fabric, is different from clays components of rocks. The Paleozoic

277

marine shales in Sichuan Basin experienced deep burial before an intense uplift, where the high

278

temperature and pressure changed the pore structure of the clay minerals. Many pores of soft clay

279

minerals in shales are lost because of strong post-compaction, especially when the rigid minerals of the

280

sample are low,16 which will significantly reduce the water content of samples (CN_33 in Figure 6b). In

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addition, the sorbed water of the sample will lose at a certain degree when the moisture-equilibrated

282

sample was transferred from the desiccator to the electronic balance for moisture measurement. The

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moisture loss in the transfer process in our experiments is up to 0.5 wt.%. Nevertheless, Figure 7

284

demonstrates that water uptake of these shales is primarily associated with clay minerals, and the linear

14


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combination scheme provides a convenient method to determine the water content of shales at any given

286

relative humidity.

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4.3 Effect of water on methane sorption

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The detrimental impact of water on gas sorption capacity has been previously reported in

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coals.20,29,38–43 However, there are relatively few detailed studies of methane sorption on

290

moisture-equilibrated shales.9,12,13 Measurements of methane sorption capacity of shale samples from

291

Sichuan Basin under dry and moisture-equilibrated conditions show that sorption capacity of dry samples

292

is substantially greater than that under fully moisture-equilibrated condition (97% RH). There are obvious

293

positive relationships between TOC content and maximum methane sorption capacity of shales under

294

both dry and moisture-equilibrated conditions at 97% RH (Figure 8), demonstrating the first-order effect

295

of organic matter rather than other minerals on methane sorption. This agrees well with the observations

296

in Posidonia and Alum shales

297

between clay minerals content and sorption capacity of these shales (Figure 8a). Clay minerals generally

298

play a role in gas sorption of low-TOC, clay-rich shales in the dry state.8,15,18

9

and Devonian-Mississippian shales 6. No obvious relationship exists

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The impact of water on methane sorption capacity of shales is further illustrated in Figure 9, which

300

demonstrates the reduction in methane sorption because of pre-sorbed water. The marine shales studied

301

show a variation of decreasing sorption capacities owing to water uptake ranging from 44 to 63%

302

depending on mineral components, type, abundance, distribution, and PSD. Experimental results

303

demonstrate a step-wise decline in methane capacity with increasing water content. Combined with the

304

water uptake process (Figure 4), the evolution of methane sorption capacity of shales as a function of

305

water content can be roughly divided into three stages: (1) initial decline stage: At the beginning of water

306

uptake, water molecules preferentially attach to the oxygen-containing functional groups, and occupy the

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polar sites of hydrophilic clay minerals. This process is also referred to as competitive sorption of water

308

and methane to the surface sites of shales. Monolayer coverage is complete when all the polar sites are

309

covered by water molecules. The monolayer moisture capacities (wm) calculated from the GAB model are

310

reached at 33% RH for CN_11 and CN_33, while they are reached at relative humidities between 33%

311

and 53% for CN_22 and CQ_14. The loss of sorption capacity at this stage is mainly related to the type,

312

nature, and abundance of hydrophilic clay minerals. Shale samples with higher clay mineral contents have

313

a greater reduction of methane sorption capacity. The reduction in sorption capacity of clay-rich CN_33 is

314

about 26% after the monolayer coverage of water, while the lost sorption capacities are less than 16% for

315

other samples. The type of clay minerals also play a role on the water uptake and thus reduction in

316

methane sorption. Water uptake of clay minerals generally decreases in the order: montmorillonite > illite >

317

kaolinite (Figure 7a).35 The composition of clay minerals in our shales is dominated by illite, which

318

adsorbs a lot of water. Conversely, water sorption capacity of organic matter is negligible in our highly

319

mature shale samples because many oxygen-containing functional groups (such as O-H) in the organic

320

matter are lost coupled with the generation of hydrocarbon,36,37 and thus the higher TOC content, the

321

lower relative loss in methane sorption of shales at the initial stage of water uptake (Table 4). CQ_14

322

shows relatively lower loss in methane sorption capacity after the monolayer coverage of water, due to

323

the low clay minerals content and high TOC content. (2) steep decline stage: At this stage, clusters of

324

water molecules form around the polar sites via hydrogen bonding among adjacent water molecules

325

following the monolayer moisture sorption. These water clusters block pore volume that would otherwise

326

be available for methane and thus remarkably reduce the methane sorption. The blockage of pore space

327

due to water clusters is dependent on the pore structure characteristics. Capillary condensation

328

preferentially occurs in micropores, which are associated with organic kerogen of shales. TOC-rich

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CQ_14 has high micropore volume, and shows considerable water uptake at > 53% RH, which

330

corresponds to capillary condensation of water in pores. Because many micropores are blocked by water

331

molecules, methane sorption capacities of the TOC-rich sample reduce remarkably. Methane sorption

332

capacity of CQ_14 decreases from 0.21 (53% RH) to 0.12 mmol/g (75% RH), meaning that about 42% of

333

initial dry methane sorption capacity is lost in this stage. The loss of sorption capacity is about 30% for

334

CN_11 (TOC=4.58%) from 33% RH (0.15 mmol/g) to 75% RH (0.10 mmol/g). The loss in methane

335

sorption capacity of low-TOC samples is relatively less than for the TOC-rich samples at this stage,

336

possibly because capillary condensation is of lesser importance here. About 20% of dry methane sorption

337

capacity is lost for CN_33 (TOC=0.96%) from 33% RH (0.09 mmol/g) to 55% RH (0.06 mmol/g). (3)

338

slow decline stage: The loss of sorption capacity and the amount of water uptake correlates until a certain

339

moisture content, above which there is no significant change in sorption capacity with further increase in

340

moisture. At this stage, many micropores have been filled by water clusters, and the capillary

341

condensation continues in macropores and interparticle voids, successively filling the pore volume with a

342

contiguous water phase. Because water molecules aggregate in macropores and capillaries, which are

343

unavailable for methane sorption, methane sorption capacities would not decrease significantly. The slow

344

decline stage is also referred to as volumetric displacement of methane molecules by water and has been

345

reported for coal but investigated to a lesser extent in shales.20 The critical moisture content for these

346

samples is achieved between 75% and 97% RH except that clay-rich CN_33 show critical moisture

347

characteristic between 53% and 75% RH. CN_33 is rich in clay minerals and low in TOC content, thus

348

the main loss in methane sorption of CN_33 occurs in the early stage of water uptake. Furthermore, it is

349

not easy to form contiguous water phase in CN_33 and the volumetric displacement has relatively less

350

effect on methane sorption.

17


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Our step-wise decrease in sorption capacity with increasing water uptake in shales differs partly

352

from (but is compatible with) previous studies on gas sorption on moist coals.20 Day et al.

20

353

linear decrease in sorption capacity of coals up to a certain critical moisture content, in which the initial

354

decline stage is unconspicuous. This could be attributed to the high content of organic matter (TOC >

355

75%) and relatively low clay minerals (clay minerals content (g/cm3) is the grain density.

374

Considering the skeletal density and porosity values derived from helium pycnometry (Table 2), the

375

amount of water at 97% RH would yield somewhat high water saturation values (>70%) in shales. Taking

376

the water contents at 75% RH, the equivalent water saturation are calculated as 27%–67% for these shales,

377

which are in the range of actual water saturation vales (10%–70%) reported for the Silurian Longmaxi

378

shales from Sichuan Basin.44 Consequently, sorption isotherms measured on dry samples will

379

overestimate sorbed gas in place, especially in clay-rich formation. Sorption capacity provided by organic

380

matter might be partly decreased because of pore blockage and volumetric displacement of water as an

381

additional effect. It is highly advisable to perform methane sorption on moisture-equilibrated samples.

382

Methane sorption capacity derived from dry sample can be considered as a maximum case, and sorption

383

data of partially moisture-equilibrated sample (75% RH) is a more realistic estimation, and that for fully

384

moisture-equilibrated samples (97% RH) is regarded as a minimum value.

385

Gas transport in unconventional shales is a combination of several flow mechanisms: desorption,

386

diffusion, and slip flow in micropores, Darcy flow (advection) in macropores of the matrix and fractures

387

networks. Capillary condensation of water in pores and capillaries not only occupies the pore spaces for

388

gas storage, but also restricts the gas transport in interconnected pores (transport pores). Experiments on

389

methane sorption and diffusion on shales have shown that there is a considerable decrease in the sorption

390

rates for moisture-equilibrated shales while the uptake rate of corresponding dry shales is relatively

391

rapid.9,33 Moreover, surface diffusion, sorbed gas molecules hopping from sorption sites to the

392

neighboring sorption sites, plays a key role in gas mass transfer of shale reservoirs.45 The presence of

393

water clusters in the pores and microfractures of shales certainly has a detrimental impact on the

394

transportation of both sorbed and free gas. Detailed investigations of kinetics of desorption and gas

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395

transport mechanism within shales will be discussed in future work.

396

5. Conclusions

397

Methane sorption isotherms on shales of Sichuan Basin at five different moisture levels were

398

measured up to pressures of 25 MPa using a manometric method. Water sorption isotherms of these

399

marine shales were also recorded at 24 °C and relative humidities (RH) from 11 to 97%. The purpose of

400

the present study was to investigate the effect of organic richness, mineral composition, and pore system

401

structure on water uptake and methane sorption characteristics of shales. The following conclusions can

402

be drawn:

403

(1) Small amounts of water have a detrimental effect on methane sorption of shales. Sorption

404

capacities of the moisture-equilibrated shales at 97% RH (0.05–0.08 mmol/g) were 44%–63% of those for

405

dry samples (0.11–0.22 mmol/g).

406

(2) The water sorption capacity of shales is controlled by clay mineralogy and a linear combination

407

scheme on a mass-fraction base provides reasonable predictions of water uptake isotherms for these

408

shales. Total clay mineral contents show a positive relationship with water uptake at 97% RH although

409

deviations from this trend are observed for clay-rich samples with low quartz contents.

410

(3) Methane sorption capacity of the marine shales studied is mainly controlled by the organic matter

411

content. Maximum sorption capacities of these shales under both dry and fully moisture-equilibrated

412

conditions correlate positively with TOC content.

413

(4) Experimental results demonstrate a step-wise decline in sorption capacity with increasing water

414

content. Evolution of sorption capacity as a function of water content of shales can be roughly

415

subdivided into three stages: (1) initial decline stage: loss in sorption capacity is attributed to

416

competitive sorption of gas and water molecules on the polar sites of hydrophilic clay minerals. (2) steep

20


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417

decline stage: clusters of water molecules block pore space and remarkably reduce methane sorption. (3)

418

slow decline stage: successive filling of macropores with a contiguous water phase and slight reduction

419

of methane sorption capacity by volumetric displacement.

420

(5) Water saturation calculated based on the porosity values and water contents at 75% RH agree

421

with actual water saturation data reported for the Silurian Longmaxi shales. This suggests that

422

experimental sorption measurements performed on partially moisture-equilibrated samples (75% RH)

423

probably provide more realistic estimations for the in-situ sorption of shale reservoirs. Methane sorption

424

capacities measured on dry samples can be considered as maximum values, and those obtained for fully

425

moisture-equilibrated samples (97% RH) are regarded as a minimum values.

426

Acknowledgments

427 428 429

Foundation of China (Grant No. 51604249, 41572109), and State Key Laboratory of Petroleum

430

References

431 432 433 434 435 436 437 438 439 440 441 442 443 444 445 446 447 448 449 450

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The authors would like to acknowledge the financial support of the National Natural Science Resources and Prospecting Independent Research Subject (Grant No. PRP/open-1606).

U.S. Department of Energy, DOE/EIA–0383, released on August, 2016. (2) Lu, X.C.; Li, F.C.; Watson, A.T. Adsorption measurements in Devonian shales. Fuel 1995,74,599– 603. (3) Curtis, J.B. Fractured shale-gas systems. AAPG Bull. 2002, 86, 1921–1938. (4) Chalmers, G.R.L.; Bustin, R.M. The organic matter distribution and methane capacity of the Lower Cretaceous strata of Northeastern British Columbia, Canada. Int. J. Coal Geol. 2007, 70, 223–239. (5) Chalmers, G.R.L.; Bustin, R.M. Lower Cretaceous gas shales in northeastern British Columbia, part 1: geological controls on methane sorption capacity. Bull. Can. Petrol. Geol. 2008, 56,1–21. (6) Ross, D.J.K.; Bustin, R.M. The importance of shale composition and pore structure upon gas storage potential of shale gas reservoirs. Mar. Petrol. Geol. 2009, 26, 916–927. (7) Zhang, T.W.; Ellis, G.S.; Ruppel, S.C.; Milliken, K.; Yang, R.S. Effect of organic-matter type and thermal maturity on methane adsorption in shale-gas systems. Org. Geochem. 2012, 47, 120–131. (8) Gasparik, M.; Ghanizadeh, A.; Bertier, P.; Gensterblum, Y.; Bouw, S.; Krooss, B.M. High-pressure methane sorption isotherms of black shales from the Netherlands. Energy Fuels 2012, 26, 4995– 5004. (9) Gasparik, M.; Bertier, P.; Gensterblum, Y.; Ghanizadeh, A.; Krooss, B.M.; Littke, R. Geological controls on the methane storage capacity in organic-rich shales. Int. J. Coal Geol. 2014, 123, 34–51. (10) Rexer, T.F.T.; Benham, M.J.; Aplin, A.C.; Thomas, K.M. Methane adsorption on shale under simulated geological temperature and pressure conditions. Energy Fuels 2013, 27, 3099–3109. 21


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(29) Lewicki, P.P. The applicability of the GAB model to food water sorption isotherms. Int. J. Food Sci. Tech. 1997, 32, 553–557. (30) Krooss, B.M.; Van Bergen, F.; Gensterblum, Y.; Siemons, N.; Pagnier, H.J.; David, P. High-pressure methane and carbon dioxide adsorption on dry and moisture-equilibrated Pennsylvanian coals. Int. J. Coal Geol. 2002, 51, 69–92. (31) Gasparik, M.; Rexer, T.F.T.; Aplin, A.C.; Billemont, P.; De Weireld, G.; Gensterblum, Y.; et al. First international inter-laboratory comparison of high-pressure CH4, CO2 and C2H6 sorption isotherms on carbonaceous shales. Int. J. Coal Geol. 2014, 132,131–146. (32) Kunz, O.; Klimeck, R.; Wagner, W.; Jaeschke, M. The GERG-2004 Wide-Range Equation of State for Natural Gases and Other Mixtures. VDI Verlag, Düsseldorf 2007; 978–3–18–355706–6. (33) Yuan, W.N.; Pan, Z.J.; Li, X.; Yang, Y.X.; Zhao, C.X.; Connell, L.D.; et al. Experimental study and modelling of methane adsorption and diffusion in shale. Fuel 2014, 117, 509–519. (34) Passey, Q.R.; Bohacs, K.M.; Esch, W.L.; Klimentidis, R.; Sinha, S. From oil-prone source rock to gas-producing shale reservoir-geologic and petrophysical characterization of unconventional shale-gas reservoirs. SPE 131350 presented at the CPS/SPE International Oil & Gas Conference and Exhibition in Beijing, China, 8–10 June, 2010. (35) Martin, R.T. Adsorbed water on clay: A review. Clays and Clay Minerals: Proceedings of the Ninth National Conference on Clays and Clay Minerals, Lafayette, Indiana, October 5–8, 1960, 28–70. (36) Mahajan, O.P.; Walker, Jr. P.L. Water adsorption on coals. Fuel 1971,50,308–317. (37) Merkel, A.; Fink, R.; Littke, R. The role of pre-adsorbed water on methane sorption capacity of Bossier and Haynesville shales. Int. J. Coal Geol. 2015,147–148,1–8. (38) Ryan, B. A discussion on moisture in coal-implications for coalbed gas and coal utilization. BC Ministry of Energy. Mines Pet. Resour. 2006, 1, 139–149. (39) Gensterblum, Y., Merkel, A., Busch, A., Krooss, B.M. High-pressure CH4 and CO2 sorption isotherms as a function of coal maturity and the influence of moisture. Int. J. Coal Geol. 2013, 118, 45–57. (40) Müller, E.A.; Rull, L.F.; Vega, L.F.; Gubbins, K.E. Adsorption of water on activated carbons: A molecular simulation study. J. Phys. Chem. 1996, 100, 1189–1196. (41) Joubert, J.I.; Grein, C.T.; Bienstock, D. Effect of moisture on the methane capacity of American coals. Fuel 1974,53,186–191. (42) McCutcheon, A.L.; Barton, W.A. Contribution of mineral matter to water associated with bituminous coals. Energy Fuels 1999,13, 160–165. (43) Gensterblum, Y.; Merkel, A.; Busch, A.; Krooss, B.M.; Littke, R. Gas saturation and CO2 enhancement potential of coalbed methane reservoirs as a function of depth. AAPG Bull. 2014, 98, 395–420. (44) Wang, F.Y.; Guan, J.; Feng, W.P.; Bao, L.Y. Evolution of overmature marine shale porosity and implication to the free gas volume. Pet. Explor. Dev. 2013, 40, 819–824. (45) Chen, Y.D.; Yang, R.T. Concentration dependence of surface diffusion and zeolitic diffusion. AIChE J. 1991, 37, 1579–1582. (46) Feng, G.X.; Chen, S.J. Relationship between the reflectance of bitumen and vitrinite in rock. Nat. Gas Ind. 1988, 8, 20–24.

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537

Figures

538 539 540

Figure 1. Map showing geological structure of the Sichuan Basin and sampling locations (modified after Yang et al. 15). The roman numbers represent different fold belts in Sichuan Basin.

541

542 543 544

Figure 2. (a) Low-pressure N2 adsorption-desorption isotherms for the shale samples; (b) Pore size distributions of the samples based on the BJH method applied to the adsorption branch of the isotherms.

545

546 547 548

Figure 3. Relationship between TOC content and (a) BET specific surface area and (b) average pore diameters of the samples.

549

24


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550 551 552

Figure 4. Water sorption isotherms for the samples at 297 K (24 °C) (The lines represent GAB fitting of the measured water sorption isotherms).

553

554 555 556 557

Figure 5. Methane excess sorption isotherms of the shale samples measured at varying relative humidity with corresponding fitted excess sorption functions (It should be noted that the evolution of the isotherms of CQ_14 is different from others).

558

559 560 561 562 563

Figure 6. Effect of (a) TOC content and (b) total clay minerals and (c) BET surface area on water content of the 97% RH moisture-equilibrated shale samples (In Figure 6a: The dote line represents the linear fitting of samples in this study (R2=0.61); the dash line represents the linear fitting of European samples measured by Gasparik et al.9 (R2=0.30)). 25


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564 565 566 567

Figure 7. (a) Water sorption isotherms of clays from Martin35; (b) Measured (solid symbols) and estimated (lines) of water uptake on selected shales samples. The water uptake isotherms are estimated based on individual mineral components on a mass-fraction base.

568

569 570 571 572 573

Figure 8. Methane sorption capacity of dry and fully moisture-equilibrated (97% RH) shale samples as a function of (a) total clay minerals and (b) TOC content. Squares and circles denote samples measured by Gasparik et al.9, and Ross and Bustin6, respectively. Gas sorption capacity of Devonian-Mississippian shales in the WCSB are measured by Ross and Bustin6 at 30 °C and 6 MPa pressure.

574

575 576 577

Figure 9. Methane sorption capacity as a function of water content of the shale samples. ①, ②, and ③ denote initial decline, steep decline, and slow decline stage, respectively.

26


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Energy & Fuels

Tables Table 1: Geochemical characteristics and mineralogy composition of the shale samples. Reqb

TOC a Sample

Stratigraphy

Quartz +

Total Carbonates

feldspars (wt. %)

Illite

Kaolinite

Chlorite

(wt. %)

(wt. %)

(wt. %)

clays

(%)

(wt. %) (wt. %)

(wt. %)

CN_11

U. Ordovician

4.83

2.8

74.0

0.0

26.0

25.0

0.3

0.8

CN_22

L. Silurian

2.87

2.8

55.4

25.4

17.2

16.2

0.0

1.0

CN_33

L. Silurian

0.96

2.8

25.3

27.7

45.5

35.0

0.0

10.5

CQ_14

L. Silurian

9.40

2.4

66.7

4.1

22.6

22.6

0.0

0.0

a

The TOC content were determined by a LECO CS230 carbon/sulfur analyzer.

b

The equivalent vitrinite reflectance (Req) were derived from bitumen reflectance according to the equation of Feng

and Chen 46.

Table 2: Pore structure parameters of the shale samples. a

b

Porosity

BET surface area

Pore volume

Average pore diameter

Equivalent water

(g/cm )

(g/cm )

(%)

(m2/g)

(cm3/g)

(nm)

saturation (%)

CN_11

2.22

2.56

13.0

28.75

0.043

6.0

27.0

CN_22

2.54

2.66

4.4

14.96

0.018

4.9

65.3

CN_33

2.51

2.74

8.4

14.95

0.027

7.1

38.0

CQ_14

2.36

2.52

6.4

31.58

0.051

2.4

67.3

Bulk density Sample

3

Skeletal density 3

a

The bulk density was determined by caliper measurements on cylindrical plug samples.

b

The skeletal density were measured using a helium pycnometer based on Boyle's Law.

c

The equivalent water saturation of shales were calculated using water contents at 75% RH according to Eq. (5).

27


c

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Table 3. Results from GAB Adsorption Model Analysis on water uptake isotherms

Shale

Clay mineral a

a

Sample

wm (mmol/g)

c

k

CN_11

0.31

17.67

0.89

CN_22

0.31

8.32

0.72

CN_33

0.25

9.39

0.87

CQ_14

0.34

7.95

0.90

Montmorillonite

8.08

7.70

0.70

Illite

1.40

180.5

0.87

Kaolinite

0.16

844.67

0.95 35

The water uptake data of clay minerals were collected from Martin .

Table 4. Moisture content, and methane sorption capacities and Langmuir parameters for shale samples. Sample

CN_11

CN_22

CN_33

CQ_14

Relative humidity

Water content

Water content

nL

PL

ρads

Lost sorption

(%)

(wt. %)

(mmol/g)

(mmol/g)

(MPa)

(kg/m3)

capacity (%)

0

0

0

0.181

3.3

433.4

0

11

0.38

0.21

-

-

-

-

33

0.72

0.40

0.153

7.1

566.7

15.5

53

1.05

0.58

0.143

10.0

648.5

21.0

75

1.58

0.88

0.099

7.7

744.9

45.3

97

4.06

2.26

0.083

7.1

916.9

54.1

0

0

0

0.113

2.7

471.4

0

11

0.29

0.16

-

-

-

-

33

0.50

0.28

0.099

6.1

551.9

12.4

53

0.72

0.40

0.095

13.2

671.8

15.9

75

1.13

0.63

0.069

9.1

778.4

38.9

97

1.76

0.98

0.063

8.7

746.9

44.2

0

0

0

0.118

7.8

508.2

0

11

0.29

0.16

-

-

-

-

33

0.46

0.26

0.087

10.0

673.1

26.3

53

0.67

0.37

0.063

10.5

-

46.6

75

1.27

0.71

0.058

11.4

-

50.8

97

2.75

1.53

0.051

11.0

-

56.8

0

0

0

0.222

2.5

405.4

0

11

0.38

0.21

-

-

-

-

33

0.53

0.30

0.215

4.2

428.0

3.2

53

0.72

0.40

0.214

5.3

376.7

3.6

75

1.81

1.01

0.123

9.0

396.9

44.6

97

4.50

2.50

0.082

17.3

-

63.1

28


High-Pressure Methane Sorption on Dry and Moisture-Equilibrated

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