Geology topics

Junbong Jang

Publications and source records attributed to Junbong Jang.

18 recordsLinked to original sources

USGS2022

Diatom influence on the production characteristics of hydrate-bearing sediments: Examples from Ulleung Basin, offshore South Korea

The Ulleung Basin Gas Hydrate field expeditions in 2007 (UBGH1) and 2010 (UBGH2) sought to assess the Basin's gas hydrate resource potential. Coring operations in both expeditions recovered evidence of gas hydrate, primarily as fracture-filling (or vein type) morphologies in mainly silt-sized, fine-grained sediment, but also as pore-occupying hydrate in the coarser-grained layers of interbedded sand and fine-grained systems. A commonality across many of these occurrences is the presence of diatoms in the fine-grained sediment. Here we tested fine-grained sediment (median grain size <12.5 μm) associated with hydrate occurrences at four UBGH2 sites (UBGH2-2-2, UBGH2-3, UBGH2-6 and UBGH2-11) to investigate potential impacts of diatoms on efforts to extract methane from hydrate, or to tap hydrocarbon reservoirs beneath hydrate-bearing sediment. Two key considerations are: the extent to which diatoms control sediment mechanical properties, and the extent to which pore-water freshening, which occurs as gas hydrate breaks down during resource extraction, alters the diatom control on sediment mechanical properties. We conducted experiments to measure sediment index properties, sedimentation behavior and compressibility to address these considerations. We relied on scanning electron microscope (SEM) imagery and X-ray powder diffraction (XRD) to characterize the sediment mineralogy. Our high-level findings are that at the ∼20–45% (by volume) diatom concentrations observed at these UBGH2 sites, sediment compressibility increases with diatom content, but diatoms only appear to increase porosity and permeability at the highest diatom concentration (∼45%). Our measurements suggest in situ compression indices of 0.35–0.55 and permeabilities on the order of 0.01milliDarcies (1 × 10 −17 m 2 ) can be anticipated at these sites. Importantly, these properties are not expected to vary significantly upon pore water freshening that accompanies gas hydrate dissociation during production.

East Sea, Ulleung Basin↗

USGS2020

Potential freshening impacts on fines migration and pore-throat clogging during gas hydrate production: 2-D micromodel study with Diatomaceous UBGH2 sediments

The methane gas hydrate stored in natural sediments is considered a potential gas resource. Countries such as China, India, Japan, and Korea are interested in commercializing this resource, and offshore field pilot tests for gas production have been conducted using depressurization methods to destabilize gas hydrate and facilitate the migration of methane to the production well. However, fine-grained sediments (fines), which are present even in coarse-grained, gas hydrate-bearing sediments, can be resuspended in the production fluid, subsequently clogging pore throats in the formation and reducing the overall production efficiency. We conducted laboratory tests to evaluate the suspension and clogging potential of fines collected from the Ulleung Basin, East Sea, Korea during the 2010 Ulleung Basin Gas Hydrate Expedition 2 (UBGH2). Experimental results reveal that diatoms are prevalent in the sediment and largely control the suspension and clogging behavior. Fluid flow experiments in 2D micromodels show clogging occurs even when injecting the minimum sediment concentration (0.1wt% in the fluid) through micromodels with pore-throat widths at the high end of the anticipated range for UBGH2 gas hydrate-bearing sands (100µm). Mobile gas/fluid interfaces forming during gas hydrate dissociation accentuate clogging by concentrating and mobilizing fines. Sedimentation tests show pore-water freshening during dissociation is not anticipated to change the potential for diatoms to become entrained in the pore water flow, even for the observed gas hydrate saturations of ~80%. Muscovite and illite are also significant components of the tested sediment, however, and pore-water freshening increases their potential for resuspension and clogging. Overall, the resuspension and clogging potential of these fine sediments should increase as gas hydrate dissociation progresses in the thin, gas hydrate-bearing sands investigated in the Ulleung Basin.

Marine and Petroleum Geology↗

USGS2020

Gas hydrate petroleum systems: What constitutes the “seal”?

The gas hydrate petroleum system (GHPS) approach, which has been used to characterize gas hydrates in nature, utilizes three distinct components: a methane source, a methane migration pathway, and a reservoir that not only contains gas hydrate, but also acts as a seal to prevent methane loss. Unlike GHPS, a traditional petroleum system (PS) approach further distinguishes between the reservoir, a unit with generally coarser sediment grains, and a separate overlying seal unit with generally finer sediment grains. Adopting this traditional PS distinction in the GHPS approach facilitates assessments of reservoir growth and production potential. The significance of the seal for the formation of a gas hydrate reservoir as well as for the efficiency in methane extraction from the reservoir as an energy resource is evident in the findings from recent offshore field expeditions, such as India’s second National Gas Hydrate Program expedition (NGHP-02). In regards to gas hydrate-bearing reservoir formation, the NGHP-02 gas chemistry data indicate a primarily microbial methane source. Fine-grained seal sediment in contact with coarser-grained reservoir sediment can facilitate that microbial methane production. Logging-while-drilling and sediment core data also indicate that the overlying fine-grained seal sediment is less permeable than the underlying, highly gas hydrate-saturated reservoir sediment. The overlying seal’s capacity to act as a low-permeability boundary is important not only for preventing methane migration out of the reservoir over time, but for also preventing water invasion into the reservoir during methane extraction from the reservoir. Ultimately, the presence of an overlying, fine-grained, low-permeability “Seal”? influences how gas hydrate initially forms in a coarse-grained reservoir and dictates how efficiently methane can be extracted as an energy resource from the gas hydrate reservoir via depressurization.

Bay of Bengal↗

USGS2020

High concentration methane hydrate in a silt reservoir from the deep-water Gulf of Mexico

We present results from 30 quantitative degassing experiments of pressure core sections collected during The University of Texas-Gulf of Mexico 2-1 (UT-GOM2-1) Hydrate Pressure Coring Expedition at Green Canyon Block 955 in the deep-water Gulf of Mexico as part of The University of Texas at Austin–US Department of Energy Deepwater Methane Hydrate Characterization and Scientific Assessment. The hydrate saturation ( S h ), the volume fraction of the pore space occupied by hydrate, is 79% to 93% within sandy silt beds (centimeters to meters in thickness) between 413 and 442 m below seafloor in 2032 m water depth. Sandy silt intervals are characterized by high compressional wave velocity ( V p ) (2515–3012 m s −1 ) and are interbedded with clayey silt sections that have lower S h (2%–35%) and lower V p (1684–2023 m s −1 ). Clayey silt intervals are composed of thin laminae of silts with high S h within clay-rich intervals containing little to no hydrate. Degassing of single-lithofacies sections reveals higher-resolution variation in S h than is possible to observe in well logs; however, the average S h of 64% through the reservoir is similar to well log estimates. Gas recovered from the hydrates during these experiments is composed almost entirely of methane (99.99% CH 4 , <100 ppm C 2 H 6 on average), with an isotopic composition (δ 13 C: −60.4‰ and −63.6‰ Vienna Peedee belemnite and δ 2 H: −178.2‰ and −179.0‰ Vienna standard mean ocean water) that suggests the methane is primarily from a microbial source. A subset of six degassing experiments performed using very small pressure decrements indicates that the salinity within these samples is close to the average seawater concentration, suggesting that hydrate either formed slowly or formed during a rapid event at least tens of thousands of years before present.

Texas, Louisiana↗

USGS2020

Pressure coring a Gulf of Mexico deep-water turbidite gas hydrate reservoir: Initial results from The University of Texas–Gulf of Mexico 2-1 (UT-GOM2-1) Hydrate Pressure Coring Expedition

The University of Texas Hydrate Pressure Coring Expedition (UT-GOM2-1) recovered cores at near in situ formation pressures from a gas hydrate reservoir composed of sandy silt and clayey silt beds in Green Canyon Block 955 in the deep-water Gulf of Mexico. The expedition results are synthesized and linked to other detailed analyses presented in this volume. Millimeter- to meter-scale beds of sandy silt and clayey silt are interbedded on the levee of a turbidite channel. The hydrate saturation (the volume fraction of the pore space occupied by hydrate) in the sandy silts ranges from 79% to 93%, and there is little to no hydrate in the clayey silt. Gas from the hydrates is composed of nearly pure methane (99.99%) with less than 400 ppm of ethane or heavier hydrocarbons. The δ 13 C values from the methane are depleted (−60‰ to −65‰ Vienna Peedee belemnite), and it is interpreted that the gases were largely generated by primary microbial methanogenesis but that low concentrations of propane or heavier hydrocarbons record at least trace thermogenic components. The in situ pore-water salinity is very close to that of seawater. This suggests that the excess salinity generated during hydrate formation diffused away because the hydrate formed slowly or because it formed long ago. Because the sandy silt deposits have high hydrate concentration and high intrinsic permeability, they may represent a class of reservoir that can be economically developed. Results from this expedition will inform a new generation of reservoir simulation models that will illuminate how these reservoirs might be best produced.

Texas, Louisiana↗

USGS2019

Downhole physical property-based description of a gas hydrate petroleum system in NGHP-02 Area C: A channel, levee, fan complex in the Krishna-Godavari Basin offshore eastern India

India’s second National Gas Hydrate Program expedition, NGHP-02, collected logging while drilling and sediment core data in Area C offshore eastern India, to investigate controls on the distribution and peak saturations of methane gas hydrate occurrences in buried channel, levee and fan deposits. Physical property results are presented here for the four Area C coring sites: NGHP-02-07, targeting an upper continental-slope channel deposit; NGHP-02-08 and -09, targeting levee deposits on either side of a channel further downslope, and NGHP-02-05, targeting a sequence of fan deposits extending out from the slope base. Coarse-grained sediment exists at each site, but site-specific differences in clay distribution provide significant controls on the gas hydrate distribution and saturation. At NGHP-02-07, only the upper ~4 m of a ~42 m-thick, relatively low clay-content, coarse-grained interval is inferred to be gas hydrate-bearing. NGHP-02-07 has a relatively thin, high-permeability overburden seal, and methane-rich fluid likely leaks from the primary reservoir. NGHP-02-08’s levee deposit seal is similarly permeable near the reservoir, but becomes less permeable toward the seafloor. Relative to NGHP-02-07, methane is retained more effectively in the NGHP-02-08 reservoir, but that reservoir is interbedded with layers of high clay-content, low gas hydrate saturation sediment, limiting the maximum gas hydrate content for NGHP-02-08. NGHP-02-09, the second levee deposit site, has a thicker, less permeable overburden than NGHP-02-08, combined with >50 m-thick, low clay-content reservoir sediments. Correspondingly, NGHP-02-09 has a thicker gas hydrate-bearing reservoir with consistently higher gas hydrate saturations than NGHP-02-08. NGHP-02-05 has abundant coarse-grained material spread over nearly the entire drilling interval, but the sediment is poorly sorted. Gas hydrate is distributed among several primarily coarse-grained layers, but gas hydrate saturations are limited by relatively high clay contents, and an overlying seal that is too thin and permeable to effectively retain methane in the reservoir.

Marine and Petroleum Geology↗

USGS2019

Permeability variation and anisotropy of gas hydrate-bearing pressure-core sediments recovered from the Krishna–Godavari Basin, offshore India

Permeability measurements were conducted on gas hydrate-bearing pressure-core sediments recovered from the Krishna-Godavari Basin during India's National Gas Hydrate Program Expedition 02. Pressure cores collected in the deep seabed of the Indian Ocean were cut and stored under high pressure and low temperature on the D/V Chikyu using pressure core analyzing tools. A total of 25 1.2-m storage chambers were transferred to Japan from India for pressure core studies using pressure-core analysis tools at the National Institute of Advanced Industrial Science and Technology. The sediment core's pressure and temperature were maintained within the hydrate stability conditions during the entire process of transfer and loading into a triaxial testing apparatus called TACTT, which can simulate the in-situ stress state under triaxial conditions. The hydrate saturation of the samples was in the range of 50¬90%. It was found that the initial effective water permeability was in range of 0.01 mD to tens of mD, depending on the hydrate saturation and the mean particle size of the host sediment. The hydrate pore space morphology is also a critical factor, and results suggest hydrates are forming in the pore centers, but also as a sediment grain coating. In a first for gas hydrate-bearing pressure cores, the permeability anisotropy was established via vertical and horizontal flow tests combined with a pore fluid flow simulation. The horizontal/vertical permeability ratio was found to be 4. Additionally, the effective stress dependency of permeability was investigated by performing flow tests at different effective stresses. Due to decreasing porosity and particle crushing, the permeability dropped by approximately 90% for an effective stress increase of 10 MPa.

Krishna–Godavari Basin↗

USGS2019

Compressibility and particle crushing of Krishna-Godavari Basin sediments from offshore India: Implications for gas production from deep-water gas hydrate deposits

Depressurizing a gas hydrate reservoir to extract methane induces high effective stresses that act to compress the reservoir. Predicting whether a gas hydrate reservoir is viable as an energy resource requires enhanced understanding of the reservoir’s compressibility and susceptibility to particle crushing in response to elevated effective stress because of their impact on the long-term permeability and geomechanical stability of the reservoir. This study investigates physical and geomechanical properties of natural sediments with and without tetrahydrofuran (THF) hydrate subjected to high effective stresses of up to 25 MPa. Experimental results show the stiffness of hydrate-free sediments is mainly governed by the stress state and history, while the stiffness of hydrate-bearing sediments reflects both the grain supporting nature of the interconnected hydrate phase and stress effects. The Poisson’s ratio of hydrate-bearing sediments at low stresses is dominated by the Poisson’s ratio of the interconnected pore-filling phases, and dominated at high stresses by elastic properties of both the skeleton and pore-filling phases. The stress-void ratio responses of hydrate-bearing sediments above the pre-consolidation stress yields a slightly convex-downward trend, suggesting compressibility is influenced by the stiffness of THF hydrate and sediment grains rather than only by void space reduction. The shape of the compression index (Cc) trend may be attributed to an increasing effective gas hydrate saturation as the total pore volume decreases under loading. The results also show that the presence of THF hydrate in sediments can mitigate particle crushing by suppressing particle rearrangement and supporting a portion of the load that would otherwise have to be carried by the sediment. Therefore, the loss of hydrate crystals during gas production may exacerbate sand crushing.

Marine and Petroleum Geology↗

USGS2019

Pressure core analysis of geomechanical and fluid flow properties of seals associated with gas hydrate-bearing reservoirs in the Krishna-Godavari Basin, offshore India

Physical properties of the sediment directly overlying a gas hydrate reservoir provide important controls on the effectiveness of depressurizing that reservoir to extract methane from gas hydrate as an energy resource. The permeability of overlying sediment determines if a gas hydrate reservoir’s upper contact will provide an effective seal that enables efficient reservoir depressurization. Compressibility, stiffness and strength indicate how overlying sediment will deform as the in situ stress changes during production, providing engineering data for well designs. Assessing these properties requires minimally-disturbed sediment. India’s National Gas Hydrates Program Expedition 2 (NGHP-02) provided an opportunity to study these seal sediment properties, reducing disturbance from gas exsolution and bubble growth by collecting a pressure core from the seal sediment just above the primary gas hydrate reservoir at Site NGHP-02-08 in Area C of the Krishna-Godavari Basin. The effective stress chamber (ESC) and the direct shear chamber (DSC) devices in the suite of Pressure Core Characterization Tools (PCCTs) were used to measure permeability, compressibility, stiffness and shear strength at the in situ vertical stress. Geotechnical properties of the predominantly fine-grained seal layer at in situ vertical stress are in typical clay sediment ranges, with low measured permeability (0.02 mD), high compressibility (Cc = 0.26 – 0.33) and low shear strength (404 kPa). Though pressure and temperature were maintained throughout the collection and measurement process to stabilize gas hydrate, the lack of effective stress in the pressure core storage chamber and the chamber pressurization with methane-free water caused core expansion and gas hydrate in a thin coarser-grained layer to dissolve. The PCCTs can reapply in situ stress with incremental loading steps during a consolidation test to account for sediment compaction. Gas hydrate dissolution can be limited by storing cores just above freezing temperatures, and by using solid spacers to reduce the storage chamber’s free volume.

Marine and Petroleum Geology↗

USGS2019

Permeability anisotropy and relative permeability in sediments from the National Gas Hydrate Program Expedition 02, offshore India

Gas and water permeability through hydrate-bearing sediments essentially governs the economic feasibility of gas production from gas hydrate deposits. Characterizing a reservoir’s permeability can be difficult because even collocated permeability measurements can vary by 4-5 orders of magnitude, due partly to differences between how various testing methods inherently measure permeability in different directions and at different scales. This study uses a customized flow anisotropy cell to investigate geomechanical and hydrological properties of hydrate-bearing sediments focusing on permeability anisotropy (i.e., horizontal, kh, to vertical, kv, permeability ratio) and relative permeability. Two cores recovered during India’s National Gas Hydrate Program Expedition 02 (NGHP-02) are tested in this study. Near in situ effective vertical stress, ~ 2MPa, the permeability anisotropy is approximately kh/kv = 1.86 for the “seal core” (from a fine-grained non-reservoir overburden sedimentary section) and kh/kv = 4.24 for the gas hydrate reservoir score with tetrahydrofuran (THF) hydrate saturation Sh = 0.8. Permeability anisotropy increases exponentially with effective vertical stress, as described by kh/kv = α(σv/MPa)^β, with α = 1.6, β = 0.22 for seal sediment and α = 3, β = 0.5 for THF hydrate-bearing sediment. Results imply the measured permeability from permeameter tests with vertical flow may underestimate the reservoir’s flow performance, which is mainly horizontal (radial) toward a vertical well. Hydrates in sediment increase the gas-entry pressure and residual water saturation, but decrease the water retention curve’s shape factor (m), resulting in a steeper curve. Distributions of available pore space sizes for flow in sediment with and without THF hydrate (Sh = 0.8) follow a log-normal distribution. Hydrate formation decreases the apparent mean pore size from ~10 µm to ~2 µm, without evidently changing the pore size distribution's standard deviation. Gas hydrate dissociation increases effective permeability and relative permeability to gas.

Journal of Marine and Petroleum Geology↗

USGS2019

Pressure core based onshore laboratory analysis on mechanical properties of hydrate-bearing sediments recovered during India's National Gas Hydrate Program Expedition (NGHP) 02

A solid understanding of the mechanical properties of hydrate-bearing sediments is essential for the safe and economic development of methane hydrate as an energy resource. In 2015, 104 pressure cores were collected, recovering sediments from above and within concentrated hydrate reservoirs in the Krishna-Godavari Basin, as part of India’s National Gas Hydrate Program Expedition 02 (NGHP-02). These cores provided minimally-disturbed sediment, retained at pressures and temperatures within the hydrate stability field, for the first-ever systematic triaxial test of dozens of subsections of hydrate-bearing pressure core sediments. Post-cruise testing in Japan, evaluated multiple physical and hydro-mechanical properties. Consolidated drained and undrained triaxial compression tests, uniaxial (unconfined in effective stress) compression tests, multistage consolidation and compression tests, and alternating strain-rate compression tests were also performed. Triaxial compression test results showed an increase in the strength and stiffness, as well as the positive dilatancy, with increasing hydrate saturation, supporting previous research on laboratory-formed and natural hydrate-bearing sediments. However, some strength results in this study were low compared to prior analyses of hydrate-bearing sediments. This low strength was likely caused by the host sediment’s small particle size and loose packing, and the relatively slow applied compression strain rate. Results from uniaxial compression and multi-step compression tests confirmed that pore-space hydrates produce an apparent cohesion in hydrate-bearing sediment. More severe strength loss in sediments during the initial loading for multistage compression was also attributable to the presence of hydrates. The applicability of this multistage compression test for determining in situ properties was not confirmed, but results do provide bounds on the in situ values. Finally, from the variable strain-rate tests, it was revealed that strength in hydrate-bearing sediment has a large strain-rate dependence.

Marine and Petroleum Geology↗

USGS2019

2D micromodel study of clogging behavior of fine-grained particles associated with gas hydrate production in NGHP-02 gas hydrate reservoir sediments

Fine-grained particles (fines) commonly coexist with coarse-grained sediments that host gas hydrate. These fines can be mobilized by liquid and gas flow during gas hydrate production. Once mobilized, fines can clog pore throats and reduce reservoir permeability. Even where particle sizes are smaller than pore-throat sizes, clogs can form due to clusters of fines. For certain types of fines, particularly swelling clays, cluster sizes depend on pore-fluid chemistry, which changes as pore-fluid freshens during gas hydrate dissociation. Fines can also be concentrated by a moving gas/liquid interface, increasing the chances of pore-throat clogging regardless of fines type. To test the relative significance of these clogging mechanisms, 2D micromodel experiments have been conducted with different pore-throat widths (20, 40, 60 and 100 m), single-phase pore-fluids (deionized water and 2M-sodium-chloride solution), and moving gas/liquid interfaces on specimens from Sites NGHP-02-09 and NGHP-02-16 (NGHP-02: National Gas Hydrate Program Expedition 02) as well as a selection of pure fines (silica silt, mica, calcium carbonate, diatoms, kaolin, and bentonite). Clogging depended on the ratio of particle-to-pore throat size, and also on pore-fluid chemistry because the pore-fluid chemistry changes effectively increased or decreased the fines cluster size relative to the pore-throat width. These interactions can be predicted based on the fines electrical sensitivity (defined by Jang and Santamarina, 2016). The fine-grained sediment component (grain size < 75 m) from the primary gas hydrate reservoir layers at Sites NGHP-02-09 and -16 show clogging via blocking or size exclusion (sieving) due to the large particles. Clogs also formed due to bridging or blocking by clusters of the smaller particles. Clogging generally occurred for pore-water sediment concentrations so low (0.2% by mass or less), that it was difficult to resolve the enhanced clogging in the presence of the gas/liquid meniscus.

Bay of Bengal↗

USGS2019

Physical property characteristics of gas hydrate-bearing reservoir and associated seal sediments collected during NGHP-02 in the Krishna-Godavari Basin, in the offshore of India

India’s National Gas Hydrate Program Expedition 02 (NGHP-02), was conducted to better understand geologic controls on gas hydrate occurrence and morphology, targeting potentially coarse-grained sediments near the base of the continental slope offshore eastern India. This study combines seismic, logging-while-drilling data, and a petroleum systems approach to provide a regional geologic context for the core- and grain-scale analyses. This multi-scale approach provides insight on the gas hydrate distribution, morphology and anticipated system response to depressurization-induced methane extraction. The study area, NGHP-02 Area B in the Krishna-Godavari Basin, contains a buried anticline/syncline structure that hosts fracture-filling gas hydrate in fine-grained sediment overlying coarser sediments with pore-occupying gas hydrate. Core- and grain-scale measurements show fine-grained sediment exerts a primary control on the distribution and morphology of gas hydrate in Area B. Diatoms in the fine-grained overburden cause porosity to increase with depth, reaching ~70% at the underlying reservoir contact. High porosity, combined with near-vertical faults, suggests the overlying sediment is an imperfect seal. This allows methane to escape the gas hydrate reservoir sediments and form primarily grain-displacing gas hydrate veins in the fine-grained overburden. Within the reservoir, fine-grained layers are interbedded with coarser-grained gas hydrate reservoir sands. Even in the reservoir sands, however, a soil classification study shows the fines content is high enough to control hydraulic and mechanical properties, such as permeability, compressibility and shear strength. Fluid motion during methane extraction from gas hydrates can mobilize those fines, which can then clog pore throats, limiting production rates. Pore-water freshening during gas hydrate dissociation can increase fines mobilization, particularly given the smectite identified in the fine-grained interbeds. Accounting for fines content and specific fines mineralogy throughout the gas hydrate petroleum system is important for predicting production efficiency from gas hydrate occurrences along the crest of the anticline in NGHP-02 Area B.

Marine and Petroleum Geology↗

USGS2018

Time-dependent pore filling

Capillarity traps fluids in porous media during immiscible fluid displacement. Most field situations involve relatively long time scales, such as hydrocarbon migration into reservoirs, resource recovery, nonaqueous phase liquid remediation, geological CO 2 storage, and sediment‐atmosphere interactions. Yet laboratory studies and numerical simulations of capillary phenomena rarely consider the impact of time on these processes. We use time‐lapse microphotography to record the evolution of saturation in air‐ or hydrocarbon‐filled capillary tubes submerged in water to investigate long‐term pore filling phenomena beyond imbibition. Microphotographic sequences capture a lively pore filling history where various concurrent physical phenomena coexist. Dissolution and diffusion play a central role. Observations indicate preferential transport of the wetting liquid along corners, vapor condensation, capillary flow induced by asymmetrical interfaces, and interface pinning that defines the diffusion length. Other processes include internal snap‐offs, fluid redistribution, and changes in wettability as fluids dissolve into each other. Overall, the rate of pore filling is diffusion‐controlled for a given interfacial configuration; diffusive transport takes place at a constant rate for pinned interfaces and is proportional to the square root of time for free interfaces where the diffusion length increases with time.

Water Resources Research↗

USGS2018

Impact of pore fluid chemistry on fine-grained sediment fabric and compressibility

Fines, defined here as grains or particles, less than 75 μm in diameter, exist nearly ubiquitously in natural sediment, even those classified as coarse. Macroscopic sediment properties, such as compressibility, which relates applied effective stress to the resulting sediment deformation, depend on the fabric of fines. Unlike coarse grains, fines have sizes and masses small enough to be more strongly influenced by electrical interparticle forces than by gravity. These electrical forces acting through pore fluids are influenced by pore fluid chemistry changes. Macroscopic property dependence on pore fluid chemistry must be accounted for in sediment studies involving subsurface flow and sediment stability analyses, as well as in engineered flow situations such as groundwater pollutant remediation, hydrocarbon migration, or other energy resource extraction applications. This study demonstrates how the liquid limit‐based electrical sensitivity index can be used to predict sediment compressibility changes due to pore fluid chemistry changes. Laboratory tests of electrical sensitivity, sedimentation, and compressibility illustrate mechanisms linking microscale and macroscale processes for selected pure, end‐member fines. A specific application considered here is methane extraction via depressurization of gas hydrate‐bearing sediment, which causes a dramatic pore water salinity drop concurrent with sediment being compressed by the imposed effective stress increase.

Journal of Geophysical Research↗

USGS2017

Geomechanical analysis of initial stage of gas production from interbedded hydrate-bearing sediment

Geomechanical stability of marine hydrate reservoirs during gas production by depressurization is the focus of this study. The reservoir considered here consists of thin hydrate rich sandy layers interbedded with mud layers. Because of the input parameter uncertainties involved, it is prudent from a geomechanical perspective to estimate the likely bounds of potential responses. A decoupled approach is presented herein for which the pressure and hydrate saturation in the sediments during gas production are obtained from multiphase flow computation, but could also be synthesized from various scenarios. This procedure is illustrated with sample problems.

Conference Paper↗

USGS2017

What has been learned from pressure cores

The advancement of pressure core acquisition and analysis technology in recent decades has enabled detailed imaging and direct measurement of naturally occurring hydrate-bearing sediments and has shed light onto hydrate habits, formation processes, fundamental physical properties, and hydrate deposit responses during gas production. This paper reviews the development and capabilities of the pressure core technology, discusses insights learned from hydrate-bearing pressure cores and inherent limitations of this technology, and concludes with suggestions for potential applications of pressure core technology for investigating hydrate deposits.

Conference Paper↗

USGS2016

Fines classification based on sensitivity to pore-fluid chemistry

The 75-μm particle size is used to discriminate between fine and coarse grains. Further analysis of fine grains is typically based on the plasticity chart. Whereas pore-fluid-chemistry-dependent soil response is a salient and distinguishing characteristic of fine grains, pore-fluid chemistry is not addressed in current classification systems. Liquid limits obtained with electrically contrasting pore fluids (deionized water, 2-M NaCl brine, and kerosene) are combined to define the soil “electrical sensitivity.” Liquid limit and electrical sensitivity can be effectively used to classify fine grains according to their fluid-soil response into no-, low-, intermediate-, or high-plasticity fine grains of low, intermediate, or high electrical sensitivity. The proposed methodology benefits from the accumulated experience with liquid limit in the field and addresses the needs of a broader range of geotechnical engineering problems.

Journal of Geotechnical and Geoenvironmental Engin↗