Geology topics

William F. Waite

Publications and source records attributed to William F. Waite.

At least 19 recordsLinked to original sources

USGS2026

Permeability and compressibility of “seal” sediment overlying the B1 sand gas hydrate reservoir: Hydrate 02 Geo Data Well, Prudhoe Bay unit, Alaska North Slope

An important element in evaluating the viability of extracting methane from a gas hydrate-bearing reservoir is establishing the effectiveness of the overlying bounding sediment as a seal to prevent gas loss, to enable effective depressurization, and to prevent fluid from entering the reservoir during production. This laboratory study presents results for index properties (e.g., grain density, grain size, and liquid limit), compressibility and swelling indices, and permeability measurements on sediment overlying the gas hydrate-bearing reservoir that was the target of the recent JOGMEC-DOE-USGS collaborative gas hydrate production testing project on the Alaska North Slope (ANS). Sediment analyzed in this study was collected during pressure coring operations in the HYDRATE 02 Geo Data Well (GDW). The ∼6.1 m sediment interval recovered in Cores 13P and 14P (878.74–884.88 m measured depth, MD) exhibited heterogeneous sedimentologic characteristics at the centimeter scale, with sediments ranging from clay to thin silty-sand lithologies. Permeability measurements and index-property correlations indicate the interval’s overall in situ vertical permeability ranges from 0.2 to 3.6 microdarcy (μD). Results for compressibility ( C C = 0.255 ± 0.02) and swelling index ( C S = 0.04 ± 0.01) are consistent with estimates based on mineralogy and liquid limit correlations. Based on the measured compressibility, the ∼3 MPa increase in effective stress during the stable phase of depressurization-induced production is anticipated to have imposed 2.43 cm of compaction per meter in the reservoir overburden, reducing permeability by ∼36%. The overburden sediment’s low in situ permeability (3 to 4 orders of magnitude below permeabilities measured in the gas hydrate-bearing part of the B1 sand (unit B)) suggests the B1 sand′s overburden provides an effective seal. Such a seal promotes efficient production by limiting fluid flow into the reservoir during depressurization-induced gas hydrate dissociation.

Alaska↗

USGS2026

Strength, stiffness, and Poisson’s ratio measurements for cements used in the well completions for the extended-duration gas production test on the Alaskan North Slope

As part of an extended-duration production test from a natural gas hydrate reservoir on the Alaska North Slope, a suite of optical-fiber sensors was encased in the completion cement to provide stable downhole monitoring around each of the four project wells. How the sensors respond to changes in the reservoir over time depends in part on properties of the LiteCRETE, ArcticCem, or Tuned Light cement in which each sensor is encased, and on how well the cement bonded to the well casing, sensors, and sediment formation. Here, we report on physical properties of the cements (compressive and tensile strength, stiffness, and Poisson’s ratio), on the downhole distribution of the cements used in each well, and on the cement bond quality. Physical property measurements are presented for cements sampled during the completion activities for the three wells completed in 2022–2023. Samples were cured while being submerged in water at 2–4 °C, then tested at intervals from ∼30 days to more than one year. After an initial period of rapid increase, cement strengths largely stabilized around 120 days in all cases, meaning that cements in all wells reached their nominal strength plateau four months or more before the production test began. Calculations based on recorded volumes of pumped cement show the subpermafrost, main hole portion of each well is encased only in the higher-density “tail” cement used in that well. Downhole cement evaluation logs from two wells demonstrate how the presence of sensors and other hardware outside the casing interferes with the cement evaluation assessment. Nonetheless, the cement evaluations indicate a generally good bond with the formation and sensors over the gas hydrate reservoir intervals.

Alaska↗

USGS2026

Oil in the Alaska North Slope gas hydrate reservoir: Micro-CT and flow simulation insights into permeability

Gas hydrate-bearing sands on the Alaska North Slope (ANS) host minor volumes of crude oil whose impact on formation permeability has never been quantified relative to a gas hydrate reservoir system. Here, we combine in situ pressure-core microcomputed-tomography (μ-CT), thermogravimetric analysis (TGA), gas-chromatography–mass-spectrometry (GC–MS), scanning-electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), and Stokes-flow simulation to (i) quantify oil saturation, (ii) infer its source, and (iii) evaluate its influence on permeability after gas-hydrate dissociation. μ-CT and SEM-EDS imaging identify the host sediment as silty, with some grain-coating clay present. Eight representative 300 3 -voxel subvolumes extracted from a preserved pressure core (Core 15P-3c, from the B1 sand (unit B), HYDRATE 02 Geo Data Well (GDW), 886.96–887.29 m measured depth, MD) exhibit porosities of 0.34–0.37 and an average oil saturation of 0.09 ± 0.03, in comparison to an independent TGA-based estimate of 0.16. GC-MS fingerprints obtained from an adjacent depressurized core (Core 17P-1, 891.37–891.44 m MD), together with oil pore habit revealed by μ-CT, suggest that the oil is partly native but also includes contributions from mineral oil-based drilling fluid contamination. Further analysis of oil–porewater interactions and flushing tests confirms that native oil saturation in the analyzed samples ranges from 0.04 to 0.08 with an average of approximately 0.06, and the oil is highly immobile. Flow simulations demonstrate that the native oil saturation of ≈0.06 reduces permeability by approximately 50% due to both pore blockage and increased flow-path tortuosity. These findings reveal the potential presence of native oil within the ANS gas hydrate reservoir and suggest that future simulation models may need to account for its impact on permeability to improve long-term performance predictions of gas and water production.

Alaska↗

USGS2026

Consolidation and permeability of the B1 and D1 gas hydrate bearing sands and associated seal sediments of the extended-duration gas production test site on the Alaska North Slope

Gas hydrate, a solid combination of gas (mostly methane in nature) and water molecules stable at low temperatures and elevated pressures, occurs naturally in marine and permafrost-associated environments. Gas hydrate reservoirs, such as those in the Alaska North Slope, have been considered potential energy resources for gas production. To understand the petrophysical and geo-mechanical characteristics of the reservoir, core samples retrieved from the site of the JOGMEC-DOE-USGS collaborative gas hydrate R&D project have been analyzed in the laboratory for their hydraulic and mechanical properties. This paper focuses on both seal and reservoir samples associated with the B1 and D1 sands, which are evaluated for index properties (including porosity, grain size distribution, liquid and plastic limits, specific surface area, and specific gravity), consolidation, permeability, and water retention. Furthermore, the reservoir core samples were tested with pore-filling, laboratory-grown tetrahydrofuran hydrate, in order to assess reservoir behavior during gas production from hydrates. Under simulated in situ stress conditions, the seal and hydrate-free reservoir cores had a permeability anisotropy ratio of k h / k v = 3.0–5.0, and k h / k v = 2.4–3.0 for the reservoir tetrahydrofuran hydrate-bearing cores. The data suggest that depressurizing the reservoir to induce hydrate dissociation alters the reservoir effective permeability in three ways: permeabilities decrease due to porosity lost (e.g., the initial reservoir thickness can decrease by up to 5% upon 7 MPa depressurization), permeability increases due to the loss of solid hydrate in the pore space, and permeability anisotropy k h / k v decreases in response to the evolving pore-space geometry. We show that given the simulated in situ gas hydrate saturations (i.e., S h = 32% in core 7P-2E and S h = 21% in core 20P-4), gas production from the dissociation of tetrahydrofuran hydrate in the two tested cores results in a net increase in effective permeability and a decrease in k h / k v . This study highlights the importance of investigating seal and reservoir sediments and the impacts of depressurization on the porosity and permeability responses during production.

Alaska↗

USGS2026

Laboratory measurements of rise velocity for individual, hydrate-free and hydrate-coated gas bubbles in water

Tracking methane transport becomes more complicated in the deep ocean where seafloor release of methane gas bubbles occurs at the high pressures and low temperatures conducive to hydrate formation on bubble surfaces. Gas hydrate formation can make the bubble surface rigid, preventing the dynamic interplay between bubble size, shape and rise velocity that gas-transport models commonly rely upon when using bubble size to predict bubble rise velocity. To better constrain gas-transport model predictions, we conducted controlled laboratory measurements of rise velocity, u z , for hydrate-free air, methane, and xenon bubbles and hydrate-coated xenon bubbles. Experimental results for u z were compared to predicted u z values from several published parameterizations used to study dissolution of gas bubbles rising in the ocean. For both hydrate-free and hydrate-coated gas bubbles, the McGinnis et al. (2006) parameterization provides the most accurate u z predictions.

Geochemistry, Geophysics, Geosystems↗

USGS2026

Design and functionality analysis of the high-stress permeameter (HSP), a device developed for measuring mechanical and hydraulic properties of gas hydrate-bearing pressure core

To characterize sediment compressibility and permeability in the presence of gas hydrate, a naturally occurring combination of water and methane that requires elevated pressure and reduced temperature to remain stable, a high-stress permeameter (HSP) device was developed. The HSP was designed to accept gas hydrate-bearing pressure core specimens in their plastic liner at pressures of 10–11 MPa. The HSP was further designed to carry out compressibility and permeability tests over a range of effective stresses while maintaining the requirements for gas hydrate stability. To verify the validity of HSP measurements of sediment consolidation properties, we tested remolded kaolin samples in the HSP and three standard fixed-ring oedometers. Furthermore, we compared the direct fluid-flow permeability measurements from the HSP with estimates based on Terzaghi’s log-time method for calculating permeability from 1-dimensional oedometer-style consolidation tests. We found agreement between all devices for consolidation (e.g., coefficients of compressibility and recompression) and permeability results. These findings indicate the suitability of the HSP for consolidation tests, as well as the log-time method for estimating permeability from oedometer consolidation tests.

Geotechnical Testing Journal↗

USGS2025

Spatial mapping of dissolved methane using an in situ sensor in Puget Sound

Release of methane, as gas bubbles or in the dissolved phase, from the seafloor has been observed in coastal waters (< 200 m) and deep ocean basins (> 1000 m). Methane dissolution within the water column affects the geochemistry of the surrounding water, leading to localized oxygen loss and potential escape to the atmosphere, particularly from shallower sites. Traditional methods for detecting and quantifying dissolved methane rely on collecting discrete water samples for ship- or land-based ex situ analysis and post processing. Here, we report on the use of a reduced response time, in situ methane sensor, the Sensor for Aqueous Gases in the Environment (SAGE), for detecting and quantifying dissolved methane concentrations in a wide range of seafloor environments. During a Fall 2022 research cruise on the R/V Thomas G. Thompson in Puget Sound, SAGE was integrated onto a towed conductivity/temperature/depth rosette and deep-sea camera system with live-stream 1 Hz telemetry and used to spatially map the concentration of methane approximately 1 m above the seafloor. The site had been previously identified as an active methane plume field characterized by gas bubbles, fluid venting, and a faulted seabed. The widespread background dissolved concentration of methane measured by SAGE was 83 nM, and a range of 78–670 nM was observed throughout the survey. The results highlight the capacity of SAGE to map the spatial and temporal variability of dissolved methane concentrations in situ and to identify and localize sites of variable methane emissions from the seafloor.

Washington↗

USGS2025

Proceedings of the Deepwater Hydrate Coring Expedition UT-GOM2-2

This report was the result of a scientific collaboration between the following institutions The University of Texas at Austin (UT), DOE, NETL, the United States Geological Survey (USGS), the Bureau of Ocean Energy Management (BOEM), The Ohio State University, Columbia University, University of New Hampshire, Oregon State University, University of Washington, Tufts University, Colorado School of Mines, and Geotek Ltd. In the summer and fall of 2023, the University of Texas (UT) Deepwater Hydrate Coring Expedition (UT-GOM2-2) drilled, cored, made downhole measurements, and analyzed samples from the seafloor to the base of the gas hydrate stability zone at Site H in the Walker Ridge Protracted Area Block 313 (Site H, WR313) in the Terrebonne basin, deepwater Gulf of America (Gulf of Mexico), herein the Gulf. This report is made up of a series of files as listed below that represents the “expedition report” of the 2023 UT-GOM2-2 Expedition.

Report↗

USGS2024

Unlearning Racism in Geoscience (URGE): Summary of U.S. Geological Survey URGE pod deliverables

The U.S. Geological Survey (USGS) is in a unique position to be a leader in diversity, equity, inclusion, and accessibility in the Earth sciences. As one of the largest geoscience employers, the USGS wields significant community influence and has a responsibility to adopt and implement robust, unbiased policies so that the science it is charged to deliver is better connected to the diverse communities it serves. Meaningful and effective improvements in implementation of diversity, equity, inclusion, and accessibility principles made within the USGS will be seen across the geoscience community. Despite this opportunity, however, the community, including the USGS, has struggled to diversify the geoscience workforce, which does not reflect the Nation’s diversity. This disparity suggests that the implementation of past policies did not achieve their desired outcomes in sustainable ways. The persistent lack of diversity across the geosciences and the racial justice protests of 2020 motivated a group of geoscience scholars to launch a global, virtual initiative known as Unlearning Racism in Geoscience (URGE) in the winter of 2021. The 16-week facilitated URGE curriculum was designed to highlight existing literature, share expert opinions, and foster discussion within groups (pods) around the world to build action plans for affecting change within their home institutions ( https://urgeoscience.org/ ). Whereas most of the approximately 4,500 participants were university faculty and students or from professional societies and nonprofit organizations, 6 pods totaling over 120 participants from the USGS joined the program—the largest participation of any Federal science agency. Summarizing the recommendations of over 100 USGS employees across the USGS who participated in URGE, this Circular represents a grassroots plan for making the USGS workforce more diverse and inclusive. To identify how peer-reviewed best practices could be implemented at the USGS, participants read existing literature, reviewed USGS policies and procedures, explored new and existing demographic data, and listened to and discussed primary interviews with scholars, all facilitated by the URGE program. This Circular leverages the efforts and momentum of the USGS URGE participants to catalyze and support positive, systemic change throughout the organization in a holistic way that represents an achievable departure from past policies that fell short of success. These recommendations are starting points. Reflecting the overall lack of diversity in the USGS workforce, the USGS URGE participants were predominantly White, meaning recommendations in this document can and should continue to evolve to include the lived perspectives and input from the broader USGS community. Finally, this summary document only highlights some of the key findings of these working groups. Additional details that may be more suitable to specific USGS Centers and programs can be found in the primary documents developed by each USGS URGE pod; a list of all registered pods can be found at https://urgeoscience.org/pods/ .

Circular↗

USGS2024

Hydraulic properties of sediments from the GC955 gas hydrate reservoir in the Gulf of Mexico

The economic feasibility of gas production from hydrate deposits is critical for hydrate to become an energy resource. Permeability in hydrate-bearing sediments dictates gas and water flow rates and needs to be accurately evaluated. Published permeability studies of hydrate-bearing sediments mostly quantify vertical permeability; however, the flow is mainly horizontal during gas production in layered reservoirs. Additionally, ASTM standards require a hydraulic gradient of 10–30 to be used during laboratory permeability measurements, but the gradient is much higher in the field, particularly near a production well. To address these issues, this study focuses on the hydraulic properties of a sandy silt subsample of the hydrate reservoir and a clayey silt subsample of the fine-grained, hydrate-free interbed recovered from a GC955 deep-water Gulf of Mexico gas hydrate reservoir. We characterize the sediment pore space with water retention curves for both hydrate-free and hydrate-bearing samples (hydrate saturation, S h =80 %). Vertical deformation with increasing stress is also quantified while consolidating the samples to the 4 MPa in situ vertical effective stress. The customized permeameter measures both the horizontal and vertical permeability with increasing stress. Results show that high hydraulic gradients lower permeability in the flow direction, possibly due to increased flow tortuosity and local sediment compaction from the high seepage force. Assuming a single permeability value, even though hydraulic gradients decrease with distance from the well, is not realistic for field estimations. The results highlight that permeability anisotropy, hydrate saturation, stress conditions, and hydraulic gradient all substantially impact reservoir permeability during production.

Geomechanics for Energy and the Environment↗

USGS2024

Terrebonne Basin northern Gulf of Mexico, 30 July-28 September 2023

In the summer and fall of 2023, the Gulf of Mexico Deepwater Hydrate Coring Expedition (UT-GOM2-2) drilled, cored, made downhole measurements, and analyzed samples from the seafloor to the base of the gas hydrate stability zone in one location (Site H, WR313) in the Terrebonne basin, deepwater Gulf of Mexico. Analyses of data and samples from the expedition will inform biological, geochemical, and geomechanical models to constrain the role of gas hydrates in the carbon cycle and the potential for gas hydrates as an energy resource. Pressure and conventional cores were collected continuously to a depth of 155.1 meters below the seafloor (mbsf). At deeper depths, cores were taken periodically from hydrate-bearing sands and their bounding muds to a total depth of 861.3 mbsf. 162.6 m of conventional core and 54.8 m of pressure core were obtained. Twelve temperature measurements were made between 27.1 and 144.5 mbsf to determine the geothermal gradient. At the seafloor, more than 4 m of sandy silt of unknown origin was encountered. Beneath this sand, to a depth of ~200 mbsf, the section was composed of interbedded mud and biogenic carbonate ooze. The biogenic ooze correlated to low density and high porosity intervals observed in the previously acquired logging while drilling (LWD) data and as measured. Calcareous nannofossil biostratigraphy constrains the entire record to the Pleistocene (< 0.91 million years) with a pronounced increase in sedimentation rate with depth. Beneath 200 mbsf, the section was predominantly composed of mud with two thicker, hydrate-bearing coarse-grained intervals, which are commonly known as the Blue and Orange sands. The dissolved gas concentration was quantified from pressure cores. In the shallow section, dissolved methane concentration increased below the sulfate-methane transition zone (SMTZ) and reaches saturation (the limit of solubility for methane) at 147 mbsf. Gas expansion was very common in conventional and depressurized pressure (conventionalized) cores below the SMTZ. At deeper depths, the methane concentration within muds bounding the Blue and Orange reservoirs was generally found to be less than saturation. The dissolved and hydrate gas composition is consistent with a microbial source, containing greater than 99.99% methane and only trace concentrations of ethane, propane, and butane. The methane to ethane ratio (C 1 /C 2 ) and the methane to ethane plus propane (C 1 /(C 2 +C 3 )) decrease with depth down to at least 678 mbsf, mainly driven by the increase in ethane with depth. It is unclear if this trend continues through the Orange sand interval. The δ 13 C isotopic signature of methane ranges between -69.9 and -78.5 ‰ Vienna Pee Dee Belemnite (VPDB). Pressure core recovery of all sandy intervals was poor. However, pressure core logs of the Orange sand show intervals of low density and high velocity, which are indicative of high hydrate saturation. One core from within the Orange sand was composed of interbedded graded sandy silt and mud. The sandy silts from this core are composed of mainly quartz and feldspar with some lithics. Most of the recovered pressure core samples are maintained at near in-situ pressure and temperature (within the hydrate stability field) at the University of Texas Pressure Core Center awaiting analysis. In the shallow section, samples will be used to determine the flux of organic carbon through the basin system, find the rate at which that carbon was consumed, and understand the microbial population responsible for these processes. In the deeper section, samples from in and around the hydrate reservoirs will be used to determine the petrophysical properties of the reservoir and bounding seals in these systems.

Gulf of Mexico, Terrebonne Basin↗

USGS2022

A review of the exploration, discovery, and characterization of highly concentrated gas hydrate accumulations in coarse-grained reservoir systems along the Eastern Continental Margin of India

The analysis of 3-D seismic data has become one of the most powerful ways to identify sand-rich gas hydrate reservoir systems and to directly identify highly concentrated gas hydrate prospects. Scientific drilling programs have shown that the occurrence of highly concentrated gas hydrate accumulations in coarse-grained, sand-rich, reservoir systems has a significant impact on the physical properties of sediments, allowing gas hydrates to be “directly detected” by conventional seismic analysis techniques. One of the most diagnostic responses of a gas hydrate-bearing sand reservoir is that of a high-velocity sedimentary section and an associated high-amplitude seismic response with a reflection polarity matching that of the seafloor. Knowledge of this physical relationship guided the Indian National Gas Hydrate Program Expedition 02 (NGHP-02) in their pre-drill site review and selection effort along the eastern continental margin of India in 2016. Within the planning, operational and post-operational data analysis phases of the NGHP-02 Expedition, scientists relied heavily on the analyses of the (1) pre-expedition acquired 3-D seismic data from offshore India, (2) downhole logging data acquired during NGHP-02 and (3) core samples and data obtained from NGHP-02 conventional- and pressure-cores to identify gas hydrates and assess the geologic controls on the formation and stability of these accumulations. Data analysis has confirmed the presence of extensive sand-rich depositional systems throughout the deepwater portions of the Krishna-Godavari and Mahanadi Basins in the Bay of Bengal. Two areas of the Krishna-Godavari Basin contain substantial gas hydrate accumulations in sand-rich systems, representing candidate sites for future potential energy exploitation.

Bay of Bengal, Krishna-Godavari Basin, Mahanadi Ba↗

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↗

USGS2022

Comprehensive pressure core analysis for hydrate-bearing sediments from Gulf of Mexico Green Canyon Block 955, including assessments of geomechanical viscous behavior and nuclear magnetic resonance permeability

Quantifying the petrophysical and geomechanical properties of gas hydrate reservoirs is essential for understanding the natural hydrate system and predicting gas production behavior for future resource development. Pressure-core analysis tools were used to characterize methane hydrate–bearing sediments recovered from the Gulf of Mexico Green Canyon Block 955, under an international collaboration with The University of Texas and the National Institute of Advanced Industrial Science and Technology. Pressure-core samples were successfully transferred from Austin, Texas to Sapporo, Japan. Index property measurements (grain size, grain density, hydration number, gas composition, thermal conductivity), along with triaxial compression, consolidation, and permeability tests with a nuclear magnetic resonance (NMR) analyzer were conducted. Compression tests at different strain rates confirmed a strain rate dependence for hydrate-bearing sediment, and an equation for predicting strength as a function of hydrate saturation and strain rate is proposed. Compression and swelling indices were obtained from high-effective stress consolidation tests. Furthermore, secondary compression coefficients for hydrate-bearing sediments were obtained, suggesting that hydrate exhibits creeping behavior on timescales of minutes to hours. A relatively high initial permeability of a few millidarcys was confirmed. In addition, the first NMR signal measurement was performed on a hydrate-bearing pressure core to acquire the NMR transverse or spin-spin ( T 2 ) distribution. Results confirm that the Schlumberger Doll Research model and Timur-Coates model predictions underestimate permeability measured directly via fluid flow. Permeability estimated using specific surface values derived from NMR T 2 distributions is in good agreement with flow test results. Finally, an extended Timur-Coates model was proposed and predicts intrinsic permeability with high accuracy.

Texas↗

USGS2022

Thermodynamic insights into the production of methane hydrate reservoirs from depressurization of pressure cores

We present results of slow (multiple day) depressurization experiments of pressure cores recovered from Green Canyon Block 955 in the northern Gulf of Mexico during The University of Texas at Austin Hydrate Pressure Coring Expedition (UT-GOM2-1). These stepwise depressurization experiments monitored the pressure and temperature within the core storage chamber during each pressure step, or “shut-in” period to better understand dissociation behavior and to provide insight on the thermodynamic state of gas hydrate reservoirs during production. The pressure rebound that occurs in response to a depressurization step occurs more slowly during later dissociation steps, likely reflecting a slower heat transfer rate, decreasing salinity gradient, and increased compressibility of the pore and surrounding fluids with progressive dissociation. We demonstrate that displacement of water by gas within the core storage chamber during successive dissociations both insulates the core and increases the compressibility of the pore and chamber fluid. The increased compressibility requires that a larger hydrate volume dissociates per unit of pressure recovery. Pressures observed during progressive dissociation steps are lower than predicted by the sample’s average salinity, with pressures approaching the freshwater phase boundary during frequent dissociation steps, suggesting that local pore-water freshening strongly influences dissociation behavior. To avoid underestimating the magnitude of pressure drawdown required to sustain dissociation in the reservoir, we suggest that hydrate production models use the freshwater phase boundary rather than a phase boundary determined from bulk salinity.

Green Canyon Block 955 (GC 955) study area, northe↗

USGS2021

Hydrate formation on marine seep bubbles and the implications for water column methane dissolution

Methane released from seafloor seeps contributes to a number of benthic, water column, and atmospheric processes. At seafloor seeps within the methane hydrate stability zone, crystalline gas hydrate shells can form on methane bubbles while the bubbles are still in contact with the seafloor or as the bubbles begin ascending through the water column. These shells reduce methane dissolution rates, allowing hydrate-coated bubbles to deliver methane to shallower depths in the water column than hydrate-free bubbles. Here, we analyze seafloor videos from six deepwater seep sites associated with a diverse range of bubble-release processes involving hydrate formation. Bubbles that grow rapidly are often hydrate-free when released from the seafloor. As bubble growth slows and seafloor residence time increases, a hydrate coating can form on the bubble's gas-water interface, fully coating most bubbles within ∼10 s of the onset of hydrate formation at the seafloor. This finding agrees with water-column observations that most bubbles become hydrate-coated after their initial ∼150 cm of rise, which takes about 10 s. Whether a bubble is coated or not at the seafloor affects how much methane a bubble contains and how quickly that methane dissolves during the bubble's rise through the water column. A simplified model shows that, after rising 150 cm above the seafloor, a bubble that grew a hydrate shell before releasing from the seafloor will have ∼5% more methane than a bubble of initial equal volume that did not grow a hydrate shell after it traveled to the same height.

Journal of Geophysical Research - Oceans↗

USGS2020

Timescales and processes of methane hydrate formation and breakdown, with application to geologic systems

Gas hydrate is an ice-like form of water and low molecular weight gas stable at temperatures of roughly -10ºC to 25ºC and pressures of ~3 to 30 MPa in geologic systems. Natural gas hydrates sequester an estimated one-sixth of Earth’s methane and are found primarily in deepwater marine sediments on continental margins, but also in permafrost areas and under continental ice sheets. When gas hydrate is removed from its stability field, its breakdown has implications for the global carbon cycle, ocean chemistry, marine geohazards, and interactions between the geosphere and the ocean-atmosphere system. Gas hydrate breakdown can also be artificially driven as a component of studies assessing the resource potential of these deposits. Furthermore, geologic processes and perturbations to the ocean-atmosphere system (e.g., warming temperatures) can cause not only dissociation, but also more widespread dissolution of hydrate or even formation of new hydrate in reservoirs. Linkages between gas hydrate and disparate aspects of Earth’s near-surface physical, chemical, and biological systems render an assessment of the rates and processes affecting the persistence of gas hydrate an appropriate Centennial Grand Challenge. This paper reviews the thermodynamic controls on methane hydrate stability and then describes the relative importance of kinetic, mass transfer, and heat transfer processes in the formation and breakdown (dissociation and dissolution) of gas hydrate. Results from numerical modeling, laboratory, and some fields studies are used to summarize the rates of hydrate formation and breakdown, followed by an extensive treatment of hydrate dynamics in marine and cryospheric gas hydrate systems.

Journal of Geophysical Research-Solid Earth↗

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↗