Effect of Pore Size Distribution on Dissociation Temperature

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Effect of pore size distribution on dissociation temperature depression and phase boundary shift of gas hydrate in various fine-grained sediments Taehyung Park, Joo Yong Lee, and Tae-Hyuk Kwon Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00074 • Publication Date (Web): 23 Mar 2018 Downloaded from http://pubs.acs.org on March 24, 2018

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Energy & Fuels

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Effect of pore size distribution on dissociation temperature

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depression and phase boundary shift of gas hydrate in various

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fine-grained sediments

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Taehyung Park1, Joo Yong Lee2 and Tae-Hyuk Kwon1* 1

Department of Civil and Environmental Engineering, Korea Advanced Institute of Science and

Technology (KAIST), Daejeon, 34141, Korea 2

Oil & Gas Research Center, Korea Institute of Geoscience and Mineral Resources (KIGAM),

Daejeon, 34132, Korea.

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Corresponding Author

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* Tae-Hyuk Kwon, Ph.D, Corresponding Author

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Assistant Professor, Department of Civil and Environmental Engineering,

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Korea Advanced Institute of Science and Technology (KAIST), Daejeon, 34141, Korea

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Tel: +82-42-350-3628

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Email: [email protected]

Fax: +82-42-869-3610

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Number of words: Number of tables: Number of figures:

4633 (without References, Figures or Tables) 1 9

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ACS Paragon Plus Environment

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Abstract

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Capillarity in small, confined pores has a pronounced effect on depression of dissociation

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temperature of gas hydrates, known as the Gibbs-Thomson effect. However, this effect remains

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poorly understood in natural fine-grained sediments with wide pore size distributions. This study

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investigated the effect of pore size distributions of fine-grained sediments on the dissociation

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temperature of gas hydrate. Gas hydrate was synthesized under partially water-saturated

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conditions in nano-sized silica gels and in various natural fine-grained sediment samples,

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including sand, silt, diatoms, a diatom-sand mixture, and clayey sediment. The synthesized

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hydrate samples were thermally dissociated under isochoric conditions, while the melting

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temperature depression and the shifted phase boundaries were monitored. We observed the

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dissociation temperature depression of approximately 0.1–0.3°C in silt, 0.2–0.4°C in the diatom

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sample, and 1.2–1.5°C in clayey silt, while no temperature depression was observed in sand. In a

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particular case of diatom-sand mixture, the dual porosity condition with the submicron-scale

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internal pores of diatoms and the macro-pores of sands, rendered dual phase boundaries, one

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with a ~0.4°C temperature depression and one with no depression, respectively. Despite the wide

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ranges of pore size, gas hydrates were preferentially formed in smaller pores; which comprise

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less than 40% of the cumulative pore volumes. This was because the initial water loci

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exacerbated the Gibbs-Thomson effect in partially water-saturated conditions. Our results

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provide clear experimental evidence on and novel insights into the effect of pore size

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distributions of fine-grained sediments on the dissociation behavior and phase boundaries of gas

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hydrates, both in the presence of free gas, or in water-limiting conditions that exhibit a

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considerable Gibbs-Thomson effect.

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Introduction

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Gas hydrates are ice-like crystalline structures comprised of hydrogen-bonded water cages

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containing gas molecules.1 Natural gas hydrates are considered to be potential energy resources

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due to the vast amount accumulated on continental margins and in permafrost regions.2-4 At the

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same time, they act as a carbon sink in the global carbon cycle,5 and as potential triggers and/or

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accelerators of geological hazards.6-9 Furthermore, the natural occurrence of carbon dioxide

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(CO2) hydrate in CO2 reservoirs in the deep ocean10 has aroused interest in a gas hydrate

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production method involving a CH4-CO2 replacement; gas hydrates are a possible solution to the

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problem of geologic CO2 storage.11-14 In all cases, gas hydrate dissociation reactions are

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unavoidably involved, understanding of the dissociation behavior of gas hydrates in natural

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sediments is thus essential. Accordingly, there have been extensive studies to understand the

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chemo-thermo-mechanical changes during the dissociation of gas hydrates in natural sediments,

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such as the phase changes,15, 16 pore water chemistry changes,17 and heat and mass transfer.18-20

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The majority of natural gas hydrates are reportedly hosted in fine-grained sediments, in locations

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such as Blake Ridge, the eastern coast of India (NGHP), Cascadia Margin, offshore Peru,

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Okushiri Ridge, Ulleung Basin (UB), Orca Basin, Sea of Okhotsk, Atwater Valley in Gulf of

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Mexico, and Hydrate Ridge.21-24 Such fine-grained sedimentary environments affect the

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formation and dissociation of gas hydrates in various ways, through the influence of negatively

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charged clay surfaces,25, 26 the release of adsorbed cations into pore water,27, 28 and the capillarity

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generated by small pore sizes.25, 29-34 In particular, gas hydrates that are confined in small pores

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are influenced by the capillary effect, which shifts the thermodynamic phase boundary to lower

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temperatures (or higher pressures). This phenomenon is called melting point depression (or

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dissociation temperature depression), often referred to as the Gibbs-Thomson effect.16, 29-33, 35-38 3


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Water molecules in confined small pores have a lower activity than unconfined molecules; their

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lowered activity requires greater thermodynamic driving forces to form and stabilize clathrate

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gas hydrates. Therefore, gas hydrates in small pores are stable under higher pressures and lower

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temperatures than those found in large pores. In turn, they dissociate at lower temperatures,

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having the phase boundary shifted. As a result, it has been reported that submicron sediment pore

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sizes cause the uplift of the base of the methane hydrate stability zone (MHSZ), and decrease its

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thickness.39, 40 The prediction of the temperature depression of the hydrate phase boundary in

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clay-rich sediments is critical to understanding the formation and dissociation of gas hydrates in

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those sediments, as their small pore size affects the phase boundary, location of the base of the

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MHSZ, hydrate morphology, and properties of hydrate-bearing sediments.

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The dissociation temperature depression and phase boundary shift of gas hydrates in small pores

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have been studied by using artificially synthesized porous silica gels, due to their well-controlled

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and narrow range of pore diameters.29-32, 35-37 Natural fine-grained sediments can have a wide

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pore size distribution over more than one order of magnitude. This is most apparent when the

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sediment is composed of various particles, including sand, silt, and clay-sized particles, or where

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coarse-grained sediments contain diatoms, which have their own sub-micron scale internal

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pores.21,

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offshore Japan, showed pore size distributions ranging from 10 nm to 1 µm and ~10 nm to 10

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µm, respectively.40, 41 However, a limited number of studies have been conducted using natural

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fine-grained sediments that have a wide pore size distribution; the dissociation behavior of gas

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hydrates in such sediments remains poorly examined.

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For instance, the sediments cored from the Kumano Basin and Nankai Trough,

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In this study, we investigated the Gibbs-Thomson effect and the dissociation temperature

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depression of CO2 hydrate in fine-grained sediments with pore sizes ranging over two orders of

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magnitude. CO2 hydrate was synthesized under water-limiting conditions in various sediment

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samples, including porous silica gels, sand, silt, diatoms, a diatom-sand mixture, and clayey

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sediment from Ulleung Basin, offshore Korea. Then, the hydrates in these sediments were

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thermally dissociated while the pressure and temperature traces were monitored. The dissociation

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temperature depression was identified and correlated to the pore size distribution of the host

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sediments using the Gibbs-Thomson model. The implication of the observations and results are

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discussed with respect to the occurrence of hydrate in the presence of free gas, the base of

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MHSZ, and the dissociation behavior during hydrate production.

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Materials and Methods

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2.1

Description of the sediment samples used

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In this study, two artificial porous samples and five natural sediment samples were used. We first

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prepared two porous silica gels (SG; Sigma-Aldrich, St. Louis, MO, USA) with a narrow range

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of pore sizes and mean pore diameters of 6 nm and 15 nm, hereafter denoted as 6SG and 15SG,

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respectively. These control samples were chosen to validate the Gibbs-Thomson model and the

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corresponding input parameters to determine the melting temperature shift. Five natural

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sediments were prepared: fine quartz sand (Ottawa F110, U.S. Silica, Frederick, MD, USA),

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crushed silica silt (Sil-Co-Sil, U.S. Silica, Frederick, MD, USA.), diatoms (Celite 545, Sigma-

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Aldrich, St. Louis, MO, USA), a mixture of diatom and sand at a 1:9 mass ratio, and a fine-

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grained sediment core (UBGH1-10B-2b) retrieved from hydrate deposits in the Ulleung Basin,

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East Sea, offshore Korea, hereafter referred to as sand, silt, diatoms, sand-diatom mixture, and

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UB sediment, respectively. The basic index and physical properties of the prepared samples,

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including mean particle diameter (D50), specific surface area (Sa), and porosity, are listed in

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Table 1. More details of the sand and the silt samples can be found in Kwon et al.,38 and details

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of the UB sediment are available in Kim et al.42

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The particle size distributions of the sediment samples were analyzed using a laser light

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scattering analyzer (Saturn DigiSizer 5200, Micromeritics, Norcross, GA, USA), as shown in

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Figure 1. The specific surface areas were measured using the nitrogen (N2) adsorption dry

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method (TriStar II 3020, Micromeritics, Norcross, GA, USA) and the methylene blue adsorption

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wet method43. Pore size distributions of the samples were estimated using mercury intrusion

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porosimetry (MIP; MicroActive AutoPore V 9600, Micromeritics, Norcross, GA, USA) for

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meso-to-macro pores larger than 10 nm, and the Barrett-Joyner-Halenda (BJH) N2

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adsorption/desorption method for nano-sized pores smaller than 20 nm, as shown in Figure 2.

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The pore sizes of 6SG and 15SG were obtained from the BJH method (Figure 2a), and the pore

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size distribution of the natural sediments (silt, diatoms, and UB sediment) were estimated by

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integrating both the MIP and BJH results to identify the broad range of the pore size

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distribution.44 The pore size distribution of the sand and sand-diatom mixture was estimated by

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MIP only, owing to a minimal presence, or lack of, of nano-sized pores in those samples (Figure

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2b).

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Samples 6SG and 15SG had mean particle diameters (D50) of approximately 250 µm and 560

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µm, and mean pore diameters of 6.5 nm and 16.2 nm, respectively. The sand (D50 = 120 µm)

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represents coarse-grained sediments or sandy sediments frequently found in natural hydrate

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deposits. The silt (D50 = 28 µm) was chosen to represent silty sediments in formations containing

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hydrate with a low specific surface area and low plasticity (e.g., Nankai Trough, Japan and

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Shenhu, South China Sea).45,

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plasticity, D50 = 4.8 µm, a clay fraction greater than 20%, and a high specific surface area of ~90

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m2/g (Table 1). The pore sizes of the silt and UB sediment differ by approximately one order of

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magnitude, with the majority of pores falling into the ranges of 0.1–10 µm and 0.01–1 µm,

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respectively. The diatom samples (D50 = 66.7 µm) had pores smaller than the sand, and had a low

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specific surface area, similar to the silt. However, the diatoms showed a pore size distribution of

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0.1–10 µm, in which two distinctive peaks were observed; one in the range of 100–400 nm,

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which were of their internal pores, and the other in the range of 1–10 µm, from their particle size.

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The diatom sample was selected in this study because many hydrate-containing formations in

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deep oceans are reported to contain diatomaceous sediment.21, 47

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The UB sediment represents clay-rich sediments with high

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The morphology and microstructures of the sediment grains were imaged using a scanning

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electron microscopy (SEM; Magellan 400, FEI Company, Hillsboro, OR, USA). Figure 3 shows

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some representative images of the samples. The presence of nano-sized pores in 6SG, 15SG, and

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the diatom sample can be seen in Figures 3a, 3b, and 3h. The SEM images of the UB sediment

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confirmed that the cored UB sample contained clay minerals (Figure 3f) and diatoms (Figure 3g)

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with nano-scale intrapores (~10 to 100 nm).

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2.2

Experimental setup

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In this study, CO2 (research-graded with 99.9% purity, Sam-O Gas Co., Daejeon, Korea) was

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used to form gas hydrates. CO2 was selected as a suitable analogue for CH4 hydrate because of

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the similarities between CO2 hydrate and CH4 hydrate, such as their crystal structures and

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physicochemical characteristics. Both CO2 hydrate and CH4 hydrate form structure I hydrates,

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and the size of CO2 and CH4 gas molecule are similar (4.36 and 5.12 Å, respectively).1 A

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cylindrical polycarbonate high pressure column with a height of 80 mm, an outer diameter of 19

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mm, an inner diameter of 6.4 mm, and an inner volume of 3.18 cm3 was fabricated to synthesize

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and dissociate CO2 hydrate in the porous samples, as shown in Figure 4. One resistance

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temperature detector (RTD; PT100; Hankook Electric Heater, Daejeon, Korea) was inserted into

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the center of the polycarbonate column to monitor the temperature of the samples. In addition,

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two pressure transducers (PX302; Omega Engineering, INC., Norwalk, CT, USA) were installed

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to monitor the pressure inside, while the inlet (CO2 gas injection part) and outlet (CO2 gas

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purging part) pressures were monitored to confirm that they were in a similar range. The pressure

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inside the column, the CO2 gas pressure in particular, was regulated by a pressurized CO2

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cylinder. The temperature was controlled by submerging the column in a temperature-controlled 8


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bath (RW3-2025; Jeio Tech, Daejeon, Korea). The temperature and pressure inside the column

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were logged with a data acquisition unit (34970A; Keysight Technologies, Santa Rosa, CA,

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USA) over the course of the hydrate formation and dissociation experiments.

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2.3

Experimental procedures

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Pre-wetted sediment sample preparation. All samples were pre-wetted with deionized water

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(DIW) at a pre-determined water content to achieve partially water-saturated conditions. Then,

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the pre-wetted samples were hand-tamped in the column to be approximately 8 cm high. The

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porosities of the packed samples are listed in Table 1.

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CO2 hydrate formation. The column was flushed with pure CO2 gas several times to remove the

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residual air inside. CO2 gas was then injected and pressurized to 3 MPa at 8°C. Thereafter, the

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temperature of the column was lowered to within the hydrate thermodynamic stability zone. The

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temperature was lowered to −2°C for the 6SG and 15SG samples, and to 1°C for the other

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samples. Upon confirmation of hydrate nucleation, exhibited by an exothermal temperature rise,

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the pressure and temperature were maintained for more than 24 h to allow sufficient time for

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CO2 hydrate formation and growth.

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Stepwise thermal dissociation of CO2 hydrate. After the completion of the hydrate formation

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process, the temperature of the column was increased in steps of 1°C every 5 h, while the

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constant volume condition was maintained with no mass flux (i.e., isochoric heating). When the

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temperature exceeded the dissociation temperature (or equilibrium temperature), CO2 hydrates

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started to melt and release free CO2 gas, thus increasing the pressure. Such step-wise heating

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continued until no distinct pressure increase was observed, which indicated the complete

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dissociation of CO2 hydrate, referred to as the first heating cycle. The temperature and pressure

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were logged every 10 s over the course of the experiments. As a result, the pressure and

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temperature traces obtained during hydrate dissociation indicate the thermodynamic phase

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equilibrium of the CO2 hydrate in the sample. Again, the reaction column was cooled to form

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CO2 hydrate (i.e., cooling cycle). To confirm the consistency and repeatability of the experiment

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results, the aforementioned, step-wise thermal dissociation procedure was repeated, referred to as

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the second heating cycle. Figure 5 shows the typical temperature and pressure traces obtained

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from the first heating, through cooling, and to the second heating cycle.

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3

Results and Analyses

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3.1

Results of porous silica glass: Validation of Gibbs-Thomson model

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Natural, gas hydrate-bearing clayey sediments are expected to have nano-scale pores that affect

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the formation and dissociation behavior of gas hydrates. The capillarity exerted by small pores

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hinders water molecules from associating with other water molecules, hence requiring lower

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temperatures, or higher pressures, for hydrate formation. This can be represented by the reduced

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water activity, which is a measure of the energy state (i.e., chemical potential) of the water

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molecules. Therefore, to identify the effects of nano-scale pore size on gas hydrate dissociation,

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CO2 hydrate stability tests with nano-sized porous silica gels (6SG, 15SG) were performed to

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validate the Gibbs-Thomson model in phase boundary calculations.

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Figure 6a shows the pressure-temperature (PT) traces of 6SG and 15SG, which are shifted

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toward lower temperatures compared to the bulk phase boundary (when the gas hydrates are

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unconfined). This confirms the depression of the CO2 hydrate dissociation temperature by small

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pores of the silica gels, as corroborated by many previous studies.29, 31, 33 Temperature shifts

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(∆Tdep) of ~5°C and ~2°C were observed for the 6SG and 15SG samples, respectively (Figure

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6a). The PT traces of the first and second heating cycles were found to be consistent, as both

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traces were in line with each other and relatively parallel to the bulk phase boundary (Figure 6b).

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The dissociation temperature depression (∆Tdep) can be modeled using the Gibbs-Thomson

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equation, as follows.31, 33, 38:

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2  γ m cos θ ∆Tdep = −  hw h d  ρ h 0 L f

  ⋅ Tbulk 

for cylindrical shaped gas hydrates

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(1)

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and

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4  γ m cos θ ∆Tdep = −  hw h d  ρ h 0 L f

  ⋅ Tbulk 

for spherical shaped gas hydrates,

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(2)

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where γ hw is the interfacial tension between CO2 hydrate and water, mh is the molar mass of the

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CO2 hydrate, ρh0 is the density of CO2 hydrate, L f is the latent heat of dissociation of CO2

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hydrate, and Tbulk is the equilibrium temperature of CO2 hydrate in a bulk condition with no

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confinement. Herein, due to the pore morphologies of the samples, the morphologies of gas

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hydrates are assumed to be cylindrical crystals in artificial porous silica gels, and spherical

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crystals in natural sediment samples.

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The phase boundaries for various pore sizes, calculated by the Gibbs-Thomson equation, were

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superimposed on the experimentally obtained phase boundaries of CO2 hydrate for 6SG and

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15SG in Figure 6b. Herein, the properties of CO2 hydrate were assumed to be equal to those

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gathered from previous literature,16, 33 that is: γ hw = 0.030 N/m, mh = 174 g/mol, cos θ = 1, ρh0

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= 1065 kg/m3, and L f = 65.2 kJ/mol. It appears that the PT traces during hydrate dissociation in

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6SG and 15SG fell within the phase boundaries of the 6–7 nm and 14–15 nm pores, respectively

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(Figure 6b). This agrees well with the BJH porosimetry results of 6SG and 15SG in Figure 2a.

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Thus, these results for 6SG and 15SG validate our method for identifying the phase boundary of

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CO2 hydrate in confined pores, and confirm the use of the Gibbs-Thomson equation and the

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physical parameters to predict the thermodynamic phase boundary of CO2 hydrate in nano-scale

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pores.

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3.2

Results of sand and silt: Coarse- versus Fine-grained sediments

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Figure 7a shows the PT traces of the sand and silt samples, which highlights the dissociation

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behavior of coarse-grained and fine-grained sediment, respectively. As expected, the PT traces of

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CO2 hydrate formed in the sand sample follow the bulk phase boundary with no melting

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temperature depression due to the sufficiently large pore sizes of sand, which are larger than 10

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µm (Figure 2b). This result is consistent with previous works by Kwon et al.16, 38 and Jang and

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Santamarina,48 which have shown that the melting temperature depression becomes observable

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when the pore sizes are less than 1 µm.

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On the other hand, CO2 hydrate formed in the silt sample was observed to dissociate at a lower

250

temperature than the bulk phase boundary, with a temperature depression (∆Tdep) of ~0.2–0.4°C.

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The PT traces were placed between the predicted phase boundaries of 200 nm and 600 nm pores

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(Figure 7b). The morphology of hydrate in silt was assumed to be spherical rather than

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cylindrical because the majority of pores in fine-grained sediments are open-ended and are

254

mutually connected (Equation 2). This implies that gas hydrate was formed in the pores of ~200–

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600 nm diameter and melted at the lower dissociation temperature. From the MIP analysis

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(Figure 2b), the pore size of the silt sample was estimated to range from 100 nm to 20 µm.

257

Accordingly, it appears that CO2 hydrate was preferentially formed in small pores, likely due to

258

the capillarity caused by the water-limiting conditions (or excess gas conditions). Furthermore, it

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was observed that the pressure began to increase near the phase boundary of the 200 nm pores

260

and gradually converged onto the phase boundary of the 600 nm pores, confirming that the

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hydrates in smaller pores dissociate earlier as the temperature increases (see 1st heating of silt in

262

Figure 7b).

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3.3

Results of Ulleung Basin sediment, diatoms, and sand-diatom mixture: Implications

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to natural fine-grained sediment

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Figure 8 shows the PT traces of the UB sediment, diatoms, and sand-diatom mixture. CO2

266

hydrate formed in the UB sediment dissociated at a lower temperature than the bulk phase

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boundary, showing a pronounced dissociation temperature depression (∆Tdep) of ~1.3–1.6°C.

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Assuming a spherical hydrate morphology, it was found that most of the CO2 hydrate

269

dissociation occurred between the phase boundaries for 45 nm and 55 nm pores. This indicates

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that gas hydrate was formed in the pores of approximately 45–55 nm for the UB sediment, which

271

exhibited the melting temperature depression when dissociated.

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It was also found that CO2 hydrate formed in the diatom sample and in the sand-diatom mixture

273

sample underwent melting temperature depression due to the capillarity caused by small pores

274

(Figures 8b and 8d). The temperature depressions (∆Tdep) were ~0.2–0.4°C in the diatoms and

275

0.4–0.5°C in the sand-diatom mixture, implying that the sizes of hydrate-containing pores are

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~150–600 nm. It was interesting to note that for the sand-diatom mixture, there was a noticeable

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pressure increase following the bulk phase boundary (as denoted in Figure 8d). This shows that

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CO2 hydrate was also formed in the pores of sand that were unaffected by capillarity due to their

279

large size, though the majority of the hydrate was formed in the small internal pores offered by

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diatoms.

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4

Discussion

283

4.1.

Analysis on sizes of hydrate-containing pores

284

The PT traces obtained during hydrate dissociation facilitated the estimation of the diameter of

285

hydrate-containing pores, as depicted in Figures 6-8. The normalized temperature depression

286

(∆Tdep/T) over the course of CO2 hydrate dissociation was plotted against the corresponding pore

287

diameter based on the Gibbs-Thomson equation. Then, the cumulative pore size distribution of

288

each sample, obtained from MIP and/or N2 adsorption methods, was superimposed, as shown in

289

Figure 9. This allowed us to examine the range of pore sizes where CO2 hydrate was formed in

290

each sample.

291

As shown in Figure 9a and 9b, CO2 hydrate formed in the dominant pores of the silica gel

292

samples. While the pore diameter of the 6SG sample mostly ranged from 4–20 nm, the hydrate-

293

containing pores were ~6–7 nm in diameter. These pores correspond to approximately 38–58%

294

of the cumulative pore size distribution, and comprise the middle of the pore size range (Figure

295

9a). It was found that hydrate was formed in these medium-sized pores in the 6SG sample.

296

Likewise, while the pores of 15SG sample ranged from 10–25 nm, most of the hydrates was

297

formed in the pores of ~14–16 nm, which correspond to the 50–75% range in the cumulative

298

pore size distribution. The experimental results of both silica gels indicated that the sediments

299

with a narrow pore size range are expected to preferentially contain gas hydrates in the dominant

300

pores.

301

The silt sample had a relatively wide pore size range (100 nm to 100 µm); however, the hydrate

302

was formed in pores of ~200–600 nm. These pores comprise just 2–7% of the cumulative

303

distribution, as shown in Figure 9c. This corroborates the fact that the excess gas condition (or

304

water-limiting condition) forces water to reside in small pores due to capillarity prior to hydrate

15


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305

nucleation. Hence, this condition leads to nucleation of CO2 hydrate in place of water in small

306

pores, despite the fact that confined small pores reduce the water activity and inhibit gas hydrate

307

nucleation. Similarly, the hydrate-containing pores in the UB sediment and diatom samples were

308

also found to be fairly small, with diameters of 45–55 nm and 150–600 nm, respectively (Figures

309

9d and 9e). These pores correspond to the lower range (15–18%) of pore sizes in the UB

310

sediment sample and 3–40% in the diatom sample, confirming the preferential formation of gas

311

hydrates in small pores.

312

In contrast, it appears that the hydrate-containing pores in the sand-diatom mixture sample have

313

a wide size distribution, from 150 nm to tens of microns, although most of the hydrate was

314

formed in small pores less than 1 µm. As can be seen in Figure 2b, the pore size distribution of

315

the sand-diatom mixture sample is presumed to exhibit two dominant pore size regimes; sub-

316

micron pores that are present in diatomaceous grains, and macro-pores formed by sand-diatom

317

skeletal structures. We presume that some hydrate crystals were formed in the macro-pores

318

larger than 1 µm, which is supported by the dissociation of the PT trace following the bulk phase

319

boundary without the Gibbs-Thomson effect, as observed in Figure 8d. It was concluded that in

320

fine-grained sediments, with a wide pore size distribution and under water-limiting condition,

321

gas hydrates preferentially form in small pores over large pores, due to the initial loci of water.

322

In turn, the thermodynamic phase boundaries of such hydrates are heavily affected by the

323

capillarity-induced Gibbs-Thomson effect.

324

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4.2. Implications for hydrate systems with free gas

326

It has been generally accepted that the Gibbs-Thomson effect prevails in submicron-scale pores

327

and causes the preferential formation of gas hydrates in sandy layers over clay-rich fine-grained

328

sediments.25, 40 This is valid in many hydrate deposits because two-phase equilibrium conditions

329

with no free gas are mostly established above the base of the MHSZ, or above the bottom

330

simulating reflector (BSR). In such hydrate regions with advective, but dissolved, methane

331

fluxes (i.e., Blake Ridge), methane hydrate is expected to form and fill the large pores of sandy

332

sediments, or grow as grain-displacing hydrates in clay-rich sediments.49 However, some field

333

evidence has also suggested the presence of free gas within the regional MHSZ.50-54 A free

334

methane gas phase has often been found in the vicinity of gas vents, where a water-limiting

335

condition is expected, such as Hydrate Ridges offshore Oregon,51, 54, 55 Shenhu area, South China

336

Sea,56 Keathley Canyon Block 151 in northern Gulf of Mexico,57 Krishna‐Godavari Basin

337

offshore India,58 and Mackenzie Delta.59 When the host sediments in these environments are rich

338

in diatoms, clay, silt or ash, hydrate nucleation can take place in small pores due to the capillarity

339

induced by the water-limiting condition. As we observed in our tests, hydrate dissociation is,

340

therefore, presumed to exhibit a considerable Gibbs-Thomson effect with a maximum

341

dissociation temperature depression of ~0.5°C in silt- and diatom-rich sediments, and ~1.5°C in

342

clay-rich sediments.

343

The presence of three-phase equilibrium (vapor, liquid, hydrate) in hydrate deposits has been

344

suggested in some deep sediments near the BSR. The BSR is considered to be an interface

345

between overlying hydrate-bearing sediment and underlying gassy sediment.60 Previous studies

346

have pointed out that the free gas saturation near the BSR varied between 1% and 2% in well 955

347

at Blake Ridge51 and at the IODP Site C0002 in Kumano Basin, offshore Japan.40 In these 17


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348

conditions, gas hydrates can be disseminated and the Gibbs-Thomson effect can be pronounced.

349

In fact, the frequent mismatch between the depths of the BSR and BMHSZ can be explained by

350

the presence of clay-dominated sediment and the resultant Gibbs-Thomson effect.25, 40 This is

351

also consistent with our observation of the depression of the dissociation temperature in the clay-

352

rich UB sediment sample.

353

Furthermore, the physical properties of hydrate-bearing fine-grained sediments are undergoing

354

continued investigation, and in many of the lab experiments, hydrate-bearing sediments can be

355

synthesized from water-limiting conditions.42, 50, 61, 62 It is worth noting that the gas hydrates

356

formed in fine-grained sediments can exhibit a considerable dissociation temperature depression

357

due to the Gibbs-Thomson effect, as we observed in this study.

358

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5

Conclusions

360

This study investigated the Gibbs-Thomson effect on the dissociation temperature depression

361

and the phase boundary of gas hydrates in fine-grained sediments, which have wide pore size

362

distributions of over more than one or two orders of magnitude. In fine-grained sediments with

363

free gas and limited water, gas hydrates preferentially form in smaller pores, less than 1 µm,

364

despite the thermodynamically unfavorable conditions due to the capillarity-induced Gibbs-

365

Thomson effect. Meanwhile, the experimental result of the sand-diatom mixture indicates that

366

even coarse-grained sediments with some diatoms can exhibit the Gibbs-Thomson effect, due to

367

the presence of submicron-scale internal pores of diatoms. It appears that dual porosity, formed

368

by the submicron diatom pores and macro-pores of the sand, is likely to produce dual phase

369

boundaries, one with a dissociation temperature depression and one without. Our experimental

370

results indicate the critical role of the pore size distribution range of fine-grained sediments in

371

governing the dissociation behavior and phase boundary of gas hydrates, in the presence of free

372

gas or in water-limiting conditions.

373 374

Acknowledgments

375

This research was supported by a grant (17CTAP-C129729-01) from Technology Advancement

376

Research Program (TARP) funded by Ministry of Land, Infrastructure and Transport of Korean

377

government, by the Korea Institute of Energy Technology Evaluation and Planning (KETEP) and

378

the Ministry of Trade, Industry and Energy (MOTIE) of the Republic of Korea

379

(20152520100760), and by the MOTIE through the Project “Gas Hydrate Exploration and

380

Production Study” under the management of the Gas Hydrate Research and Development

381

Organization (GHDO) of Korea and the Korea Institute of Geoscience and Mineral Resources

382

(KIGAM). The data presented in this paper can be found in the text, figures or in the table, and 19


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383

the data can be requested to the author by email ([email protected]).

388 389

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547

List of Table

548 549

Table 1. Physical and index properties of sediment samples used in this study

26


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550 551

Energy & Fuels

Table 1. Physical and index properties of sediment samples used in this study Sample 6 nm silica gel (6SG)

Properties

15 nm silica gel (15SG) Sand

Silt

UB sediment

Diatom

Sand-diatom mixture (90%sand+10%diatom) 552 553 554 555 556 557

D50 = 247 µm Sa = 447 m2/g (dry), 1028 m2/g (wet) φ = 0.72 D50 = 555 µm Sa = 310 m2/g (dry), 872 m2/g (wet) φ = 0.70 D50 = 120 µm Sa = 0.02 m2/g φ = 0.46 D50 = 28 µm Sa = 0.85 m2/g (dry), 2.8 m2/g (wet) φ = 0.48 D50 = 5 µm Sa = 32 m2/g (dry), 90 m2/g (wet) φ = 0.62; PL = 46; LL = 62 D50 = 67 µm Sa = 1.8 m2/g (dry), 3.7 m2/g (wet) φ = 0.69 D50 = 123 µm Sa = 19 m2/g (dry) φ = 0.47

Note: D50 is the mean particle diameter; Sa is the specific surface area; φ is the porosity; PL is the plastic limit; and LL is the liquid limit. The specific surface area was measured by the gas adsorption method (or dry method) and/or the methylene blue adsorption method (or wet method; Santamarina et al., 2002).

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List of Figures

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Figure 1. Grain size distributions of the sediments used in the experiments.

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Figure 2. Pore size distributions of (a) the artificial porous silica gels and (b) the natural sediments.

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Figure 3. SEM images of artificial porous silica gels with 6 nm pores (a), 15 nm pores, sand (c), silt (d), UB sediment (e,f,g), and diatom (h).

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Figure 4. A schematic drawing of the experimental setup.

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Figure 5. The temperature and pressure traces of Sample SG15 during CO2 hydrate formation and dissociation.

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Figure 6. (a) PT traces of CO2 hydrate formed in the 6SG and 15SG samples, and (b) the shifts of their phase boundaries during dissociation. The superimposed dotted lines were predicted by the Gibbs-Thomson equation.

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Figure 7. (a) PT traces of CO2 hydrate formed in the sand and silt samples, and (b) the shifts of their phase boundaries during dissociation. The superimposed dotted lines were predicted by the Gibbs-Thomson equation.

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Figure 8. (a) PT traces of CO2 hydrate formed in the UB sediment sample, (b) PT traces of CO2 hydrate formed in the diatom and sand-diatom mixture samples, (c) the shifts of the phase boundaries of CO2 hydrate in the UB sediment sample, and (d) the shifts of the phase boundaries of CO2 hydrate in the diatom and sand-diatom mixture samples. The superimposed dotted lines were predicted by the Gibbs-Thomson equation. Figure 9. Sizes of hydrate-containing pores. The normalized dissociation temperature depression (∆Tdep/T) and the cumulative pore volume distribution versus the pore diameter: (a) 6SG, (b) 15SG, (c) silt, (d) UB sediment, (e) diatom, and (f) sand-diatom mixture. The solid lines were calculated from the Gibbs-Thomson model, and the dashed lines were redrawn from the results in Figure 2. The data points indicate the experiment data, and the shaded areas represent the sizes of pores containing CO2 hydrate.

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Figure 1. Grain size distributions of the sediments used in the experiments.

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Figure 2. Pore size distributions of (a) the artificial porous silica gels and (b) the natural sediments.

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Figure 3. SEM images of artificial porous silica gels with 6 nm pores (a), 15 nm pores, sand (c), silt (d), UB sediment (e,f,g), and diatom (h).

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Figure 4. A schematic drawing of the experimental setup.

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Figure 5. The temperature and pressure traces of Sample SG15 during CO2 hydrate formation and dissociation.

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Figure 6. (a) PT traces of CO2 hydrate formed in the 6SG and 15SG samples, and (b) the shifts of their phase boundaries during dissociation. The superimposed dotted lines were predicted by the Gibbs-Thomson equation.

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Figure 7. (a) PT traces of CO2 hydrate formed in the sand and silt samples, and (b) the shifts of their phase boundaries during dissociation. The superimposed dotted lines were predicted by the Gibbs-Thomson equation.

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Figure 8. (a) PT traces of CO2 hydrate formed in the UB sediment sample, (b) PT traces of CO2 hydrate formed in the diatom and sand-diatom mixture samples, (c) the shifts of the phase boundaries of CO2 hydrate in the UB sediment sample, and (d) the shifts of the phase boundaries of CO2 hydrate in the diatom and sand-diatom mixture samples. The superimposed dotted lines were predicted by the Gibbs-Thomson equation.

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Figure 9. Sizes of hydrate-containing pores. The normalized dissociation temperature depression (∆Tdep/T) and the cumulative pore volume distribution versus the pore diameter: (a) 6SG, (b) 15SG, (c) silt, (d) UB sediment, (e) diatom, and (f) sand-diatom mixture. The solid lines were calculated from the Gibbs-Thomson model, and the dashed lines were redrawn from the results in Figure 2. The data points indicate the experiment data, and the shaded areas represent the sizes of pores containing CO2 hydrate.

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Figure 1. Grain size distributions of the sediments used in the experiments. 321x246mm (300 x 300 DPI)


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Figure 2. Pore size distributions of (a) the artificial porous silica gels and (b) the natural sediments. 643x246mm (300 x 300 DPI)


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Figure 3. SEM images of artificial porous silica gels with 6 nm pores (a), 15 nm pores, sand (c), silt (d), UB sediment (e,f,g), and diatom (h). 162x237mm (300 x 300 DPI)


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Figure 4. A schematic drawing of the experimental setup. 225x145mm (300 x 300 DPI)


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Figure 5. The temperature and pressure traces of Sample SG15 during CO2 hydrate formation and dissociation. 500x208mm (300 x 300 DPI)


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Figure 6. (a) PT traces of CO2 hydrate formed in the 6SG and 15SG samples, and (b) the shifts of their phase boundaries during dissociation. The superimposed dotted lines were predicted by the Gibbs-Thomson equation. 643x246mm (300 x 300 DPI)


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Figure 7. (a) PT traces of CO2 hydrate formed in the sand and silt samples, and (b) the shifts of their phase boundaries during dissociation. The superimposed dotted lines were predicted by the Gibbs-Thomson equation. 643x246mm (300 x 300 DPI)


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Figure 8. (a) PT traces of CO2 hydrate formed in the UB sediment sample, (b) PT traces of CO2 hydrate formed in the diatom and sand-diatom mixture samples, (c) the shifts of the phase boundaries of CO2 hydrate in the UB sediment sample, and (d) the shifts of the phase boundaries of CO2 hydrate in the diatom and sand-diatom mixture samples. The superimposed dotted lines were predicted by the Gibbs-Thomson equation. 379x290mm (300 x 300 DPI)


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Figure 9. Sizes of hydrate-containing pores. The normalized dissociation temperature depression (∆Tdep/T) and the cumulative pore volume distribution versus the pore diameter: (a) 6SG, (b) 15SG, (c) silt, (d) UB sediment, (e) diatom, and (f) sand-diatom mixture. The solid lines were calculated from the GibbsThompson model, and the dashed lines were redrawn from the results in Figure 2. The data points indicate the experiment data, and the shaded areas represent the sizes of pores containing CO2 hydrate. 209x240mm (300 x 300 DPI)


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Effect of Pore Size Distribution on Dissociation Temperature

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