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USGS2020

Nanoscale molecular composition of solid bitumen from the Eagle Ford Group across a natural thermal maturity gradient

Microscopic solid bitumen is a petrographically defined secondary organic matter residue produced during petroleum generation and subsequent oil transformation. The presence of solid bitumen impacts many reservoir properties including porosity, permeability, and hydrocarbon generation and storage, among others. Furthermore, solid bitumen reflectance is an important parameter for assessing the thermal maturity of formations with little to no vitrinite. While the molecular composition of solid bitumen will strongly impact associated parameters such as the development of organic matter porosity, hydrocarbon generation, and optical reflectance, assessing the molecular composition of solid bitumen in situ within shale reservoirs can be challenging due to the small grain sizes (often ≤1 μm in diameter) and the inherent heterogeneity of shale formations. Here we employ the recently developed atomic force microscopy based infrared spectroscopy (AFM-IR) technique to investigate solid bitumen molecular composition in situ within shale samples from the Late Cretaceous Eagle Ford Group. These samples possess sulfur-rich type II kerogens that span a natural thermal maturity gradient from early oil generation to the dry gas window. The application of AFM-IR allows for the rapid collection of thousands of compositional measurements from solid bitumen with ∼50 nm resolution. Our results indicate that (i) solid bitumen from the lower Eagle Ford displays both intra- and intergranular variation in the relative abundance of CH 2 , C═C, and C═O moieties present; (ii) this molecular variation tends to, but does not always, decrease with an increase in thermal maturity; and (iii) the solid bitumen composition between samples, from an atomic ratio perspective, is more similar than analysis of bulk kerogen isolates would indicate. These findings are discussed with perspective toward understanding the impact of thermal stress on the composition of secondary organic matter within the Eagle Ford Shale and highlight the growing awareness that organic matter heterogeneity within petroliferous mudrocks extends down to the nanoscale regime.

Energy and Fuels↗
USGS2020

Exploring methane behavior in Marcellus Shale micropores via contrast matching neutron scattering

Petroleum in shale reservoirs is hosted in organic matter and mineral pores as well as in natural fractures and voids. For thermally mature plays, e.g., the Marcellus Shale, methane and other light alkane gases are thought to be primarily contained in organic matter pores with radii ≦50 nm. Thus, in order to understand natural gas occurrence, transport, storage, and recoverability within unconventional reservoirs at the dry-gas stage of thermal maturity, it is critical to characterize the associated organic matter porosity across length scales from 50 nm down to the angstrom level. We utilized wide Q-range neutron total scattering to characterize deuterated methane (CD 4 ) adsorption at 60ºC up to the zero average contrast (ZAC) pressure (~60 MPa) within two mineralogically different samples collected from the same producing interval from the Middle Devonian Marcellus Shale. The neutron scattering approach used here provides structural information from the inter-atomic regime up to a nominal pore radius of ~12.5 nm and, by reaching the CD 4 ZAC pressure (~60 MPa), it is possible to examine the distribution of open versus closed pores within this pore size range in the samples. Our results indicate that ~10% of the largest pores measured are closed to CD 4 for a quartz-rich sample whereas up to 25% of pores with a nominal radius of ~12.5 nm are inaccessible within a sample with an equivalent proportion of quartz, carbonate, and clay. As pore size decreases, accessibility also decreases; all pores with radii ~0.5 nm are effectively closed to CD 4 in both samples. Additionally, up to ~4.5× more CD 4 is adsorbed within the quartz-rich sample at 60 MPa and we see no evidence for densification of CD 4 within the shale pores. These findings suggest that, for shale samples within the dry-gas window, (i) nanometer-scale porosity is primarily located within organic matter, (ii) the amount of available nano-porosity can vary widely over meter scales, and (iii) mineralogy plays a secondary role in dictating methane behavior within these systems.

West Virginia↗
USGS2021

Organo-facies and mineral effects on sorption capacity of low-maturity Permian Barakar shales from the Auranga Basin, Jharkhand, India

Shales associated with the Lower Permian (Barakar Formation) sediments of the Auranga Coalfield, India, occur in the immature–early mature stage. The sorption capacity of Barakar shale samples has been studied through high-pressure methane (CH 4 ) adsorption and low-pressure N 2 gas adsorption (LPN 2 GA) methods, supported with proximate analyses, programmed pyrolysis, optical petrography, and with energy-dispersive spectroscopy, X-ray diffraction, and inductively coupled plasma mass spectrometry. The sorption capacity is a function of the organic and inorganic constituents present in the shale samples. The methane sorption capacity (MSC) and Langmuir volume of the shale samples vary from 0.217 to 0.314 and 0.315 to 0.429 mmol/g rock, respectively. The BET-calculated surface area of the studied shales varies from 8.12 to 30.36 m 2 /g. The sorption capacities show the importance of the total organic content (TOC) through weak but positive correlations with MSC ( r 2 = 0.45) and S 1 values (mg hydrocarbons/g rock from programmed pyrolysis; r 2 = 0.40). Moreover, apparent inverse relationships were observed between MSC and clay mineral abundances, suggesting that individual clay mineral types may influence MSC, although more work is needed. The TOC-normalized MSC (MSC*) of shale samples shows a positive trend with quartz plus clay mineral content and ash yield of r 2 = 0.64 for both. In addition, MSC* shows a negative logarithmic relationship with S 1 + S 2 ( r 2 = 0.63) and a positive linear relationship with TOC-normalized total organic matter (TOM*) ( r 2 = 0.88, when 5 low TOM* samples are excluded) indicating complex relationships possibly including bitumen retention in the sample pore spaces. The micropore study of the samples through LPN 2 GA, applying Dubinin–Radushkevich, Dubinin–Astakhov, and density functional theory models, shows the dominance of micro-mesopore concentrations in the shale matrix of ∼2 nm pore diameter. However, these pores might be present as blind or closed pores. The presence of thorium and zirconium is reflective of terrigenous detrital matter, i.e., moderately to strongly recycled sediments. The fluviatile facies of deposited shales in the Auranga Coalfield are noted by the significant presence of kaolinite (32.5–78.3%), which suggests the importance of its effect on the sorption capacity of proximal terrigenous shales.

Jharkhand↗
USGS2022

Permeability measurement and prediction with nuclear magnetic resonance analysis of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Permeability of porous media, such as oil and gas reservoirs, is the crucial material parameter for predicting their hydraulic behavior. A nuclear magnetic resonance (NMR) analyzer is widely used as a powerful tool to predict permeability of various media. NMR T 2 (transverse or spin–spin) relaxation time distribution, which is related to pore size distribution, gives the information to allow calculation of effective (initial) permeability. In this study, we investigate effective, intrinsic (absolute), and relative water and gas permeabilities of hydrate-bearing pressure core samples. These samples were recovered from the Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well by sidewall pressure coring and then analyzed in a laboratory using both fluid flow test and NMR analyzer. The peak of the NMR T 2 distribution was measured at 10–20 ms using a laboratory NMR analyzer, which compares well with in situ measurements obtained via logging while drilling NMR data for two samples with high gas hydrate saturations ( S h = 76% and 74%). Further, comparison of laboratory NMR T 2 distribution after hydrate dissociation revealed that the hydrate existed in large pore spaces. Effective permeabilities predicted by the Timur-Coates (TC) model and the Schlumberger-Doll-Research (SDR) model, with T 2 cutoff 33 ms, were about an order of magnitude less than the laboratory measured values. Alternative TC model-based calculations with the T 2 cutoff reduced to 10 ms and a newly developed hydraulic radius model better matched the laboratory data. For the analysis of the intrinsic permeabilities, the TC model with a T 2 cutoff of 33 ms and SDR model were greater than the laboratory derived values, while the hydraulic radius model more closely matched the laboratory-derived values. In addition, permeability measurements were also made relative to gas and water under constant three-phase flow (water–gas–hydrate) conditions. After hydrate dissociation, a relative permeability curve was developed for each of the analyzed core samples based on the Corey petrophysical model. The results indicate that the gas permeability changed rapidly at high water saturation around 90%. Thus, we infer that the selection of relative reservoir parameters should focus on the higher water saturation conditions.

Alaska↗
USGS2022

Planning and operations of the Hydrate 01 Stratigraphic Test Well, Prudhoe Bay Unit, Alaska North Slope

The National Energy Technology Laboratory, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey are leading an effort to conduct an extended gas hydrate production test in northern Alaska. The proposed production test required the drilling of an initial stratigraphic test well (STW) to confirm the geologic conditions of the proposed test site. This well was completed in January 2019 in cooperation with the Prudhoe Bay Unit Working Interest Owners. The Prudhoe Bay Unit Hydrate-01 STW was spudded on 10-December-2018. Downhole data acquisition was completed on 25-December-2018, and the rig was released on 01-January-2019. The Hydrate-01 STW was drilled in two sections, including the surface hole that was drilled to a depth of 2248 ft measured depth (MD) (685 m MD) and cased, and the production hole section that was drilled to a depth of 3558 ft MD (1084 m MD) and also cased. A thermally chilled mineral-oil-based mud was used in the main (production) hole section of the well to maintain wellbore stability and quality of the wellbore acquired data. The primary wellbore data were acquired using logging-while-drilling tools. A sidewall pressure core system was also deployed to gather grain size and other data needed for the design of the future production test wells. In addition to confirming the geologic conditions at the test site, the Hydrate-01 STW was designed to serve as a monitoring well during future field operations. Therefore, two sets of fiber-optic cables, each including a bundled distributed acoustic sensor (DAS) and a distributed temperature sensor (DTS), were clamped to the outside of the production casing and cemented in place. In March 2019, the project team acquired three-dimensional (3D) DAS vertical seismic profiling data in the Hydrate-01 STW. Temperature surveys were also acquired with the DTS as deployed in the Hydrate-01 STW during the completion of the well and nearly continuously since March-2019.

Alaska↗
USGS2022

Gas hydrate saturation estimates, gas hydrate occurrence, and reservoir characteristics based on well log data from the hydrate-01 stratigraphic test well, Alaska North Slope

The Hydrate-01 Stratigraphic Test Well was drilled at the Kuparuk 7-11-12 site on the Alaska North Slope in December 2018. Sonic log data provide compressional (P) and shear (S) slowness from which we determine gas hydrate saturation ( S gh ) estimates using effective medium theory. The sonic S gh estimates compare favorably with S gh estimated from resistivity and nuclear magnetic resonance (NMR) logs, showing that gas hydrate occupies up to approximately 90% of the pore space in the target reservoir sands. The informally named B1 sand (2294 feet below mean sea level) shows lower V P / V S ratios than the D1 sand (2770 feet below mean sea level), with the lower part of the B1 sand showing lower V P / V S ratios than the upper part of the B1 sand. This corresponds to a stiffer, or more “cemented”, behavior for the lower B1 sand and less cemented behavior for the D1 sand. This trend could be due to differences in the reservoirs themselves or in the gas hydrate morphology or to both factors. We observe that the presence of gas hydrate in the upper B1 sand has greater impact on hydraulic permeability (measurements suggest a greater difference between intrinsic and effective permeability) than in the D1 sand, possibly related to gas hydrate morphology but more likely due simply to higher gas hydrate saturations in the upper B1 sand. Analyses of S gh relative to porosity, shale fraction, and intrinsic permeability show that reservoir quality (as represented by these three metrics) exerts control on gas hydrate saturation. Grain size and mineralogy data show somewhat smaller grains and better sorting in the D1 reservoir relative to the upper B1 reservoir and smaller grains and greater clay fraction in the lower B1 reservoir relative to the other two reservoir zones. Together, these data suggest that reservoir characteristics play a role in the observed V P / V S patterns, but gas hydrate morphology (possibly varying with saturation) must also be considered.

Alaska↗
USGS2022

New insights into the occurrence and implications of mobile water in gas hydrate systems

Gas hydrate production technologies commonly feature reservoir depressurization. Depressurization occurs when a pressure gradient is established in a well, drawing mobile water from the reservoir and reducing reservoir pressure. As such, the occurrence of mobile water is a necessary condition for effective gas production from gas hydrate reservoirs using common borehole-based methods. However, recent field programs have revealed that mobile water exists widely within the overall gas hydrate reservoir system, including within overlying and underlying units once thought of as virtually impermeable seals. Further, excess free water may also be commonly found in hydrate-free or hydrate-poor permeable strata interbedded within the larger gas hydrate reservoir system. Such internal sources of water are complex to characterize, difficult to explain, potentially highly heterogeneous, and may pose significant challenges to depressurization-based production. This report summarizes the general occurrence of water in gas hydrate systems and select technical implications.

Journal of Energy and Fuels↗
USGS2022

Advanced distributed acoustic sensing vertical seismic profile imaging of an Alaska North Slope gas hydrate field

Gas hydrates are found in significant quantities on the North Slope of Alaska in subpermafrost sand units and intermixed in lower portions of permafrost within the hydrate stability window. While conventional surface seismic data and established imaging methods can indicate the presence of gas hydrate reservoirs, producing high-resolution images of (seismically) thin layers remains challenging due to the preferential attenuation of the higher-frequency data components. An alternative strategy is to use distributed acoustic sensing (DAS) involving cementing optical fibers into boreholes to measure seismic wavefield energy closer to the strata of interest using vertical seismic profiling (VSP). DAS VSP imaging takes advantage of the shorter travel paths and reduced attenuation to generate higher-resolution near-well images. We illustrate these benefits on a DAS VSP data set acquired at the Hydrate-01 stratigraphic test well located in the Prudhoe Bay Unit of Alaska where significant gas hydrate deposits have been detected in two subpermafrost sand layers that are intended for long-duration production testing. Our DAS data preprocessing workflow effectively isolates the upgoing compressional-wave (P-wave) reflections required for subsurface acoustic imaging. After applying three-dimensional (3-D) tomography to improve the quality of the 3-D migration velocity model, we use 3-D reverse-time migration (RTM) to develop high-quality images of the two target sands and minor near-well faulting. We validate our RTM images through highly accurate well-ties with previously acquired petrophysical log data. This study demonstrates that combining 3-D RTM imaging with DAS VSP data provides significant value to gas hydrate and similar projects, and it suggests that more advanced inversion approaches such as (elastic) least-squares RTM could recover higher-resolution and more quantitative estimates of subsurface reflectivity, which would be valuable for refining the understanding of gas hydrate systems.

Alaska↗
USGS2022

Review of past gas Production attempts from subsurface gas hydrate deposits and necessity of long-term production testing

This paper summarizes the conditions, applied techniques, results, and lessons of major field gas production attempts from gas hydrates in the past and the necessity of longer term production testing with the scale of years to fulfill the gap between the currently available information and the knowledge required for commercial development. The temporal and spatial scales of field production test projects employing depressurization have expanded since 2002. The results from the projects have proved the applicability of these techniques in both onshore and offshore conditions. However, many technical and reservoir condition-related issues have emerged in gas production, and the gap between current status and industrial requirements is still large. Sand control, artificial lift, and related flow assurance issues are common technical issues that impact onshore and offshore production testing operations. Different reservoir responses were observed well by well, and discrepancy between model predictions and actual field measurements were seen, although reasonable matches were made for short-term behaviors. Those observations suggest that temporal change of the wellbore and near-wellbore conditions and reservoir heterogeneity that cannot be fully modeled have caused complex short-term responses to the depressurization operations. To ensure the long-term operational stability and reliability of the prediction technologies for production behaviors that are essential for commercialization of gas hydrate resources, gas hydrate production testing with comparable duration with commercial operations are necessary. Due to the locality of geological conditions in gas hydrate reservoirs, numerous gas production tests will be required to understand the factors controlling gas production.

Journal of Energy and Fuels↗
USGS2022

Scientific results of the Hydrate-01 Stratigraphic Test Well Program, Western Prudhoe Bay Unit, Alaska North Slope

The United States Department of Energy, the MH21-S Research Consortium of Japan, and the United States Geological Survey are collaborating to enable gas hydrate scientific drilling and extended-duration reservoir response testing on the Alaska North Slope. To feasibly execute such a test, a location is required that is accessible from existing roads and gravel pads and that can be occupied without disrupting ongoing industry operations. A review of potential locations meeting these criteria determined the likely occurrence of gas hydrate in two fine-grained marginal-marine sands of Tertiary age in the vicinity of the inactive “Kuparuk State 7-11-12” exploration pad in the western Prudhoe Bay Unit (PBU). Existing well and seismic data for that site were insufficient to preclude the potential for free gas occurrence within the deeper (and most prospective) target sand. Therefore, with support from the PBU Working Interest Owners, Alaska Department of Natural Resources, and Petrotechnical Resources Alaska, the Hydrate-01 Stratigraphic Test Well (STW) was drilled in December 2018 to confirm the suitability of the site for future gas hydrate scientific testing. The Hydrate-01 well was successfully drilled to −3290 ft (1003 m) subsea vertical depth at a bottom hole location of approximately 900 ft (∼275 m) east of the surface location. The drilling program featured acquisition of a full suite of logging while drilling data, the collection of side-wall pressure cores, and the installation of distributed temperature and distributed acoustic sensor fiber-optic cables. The log data acquired confirmed the occurrence of gas hydrate at high saturation in two target sands. Integrated evaluation of log and sidewall core data provide petrophysical and geomechanical property information that allow for potential reservoir response to depressurization to be simulated. The deeper “B1 sand” is deemed to be most favorable for reservoir response testing as a result of confirmed gas hydrate occurrence in sediments of high intrinsic permeability, location within 100 ft (30 m) of the base of gas hydrate stability, and minimal risk for direct communication with permeable water-bearing (hydrate-free) zones. The shallower “D1 sand” provides a secondary target that is differentiated by colder in situ temperatures and the interpreted direct hydraulic communication to a lower section of non-hydrate-bearing, water-saturated sand. The Hydrate-01 log data also confirm the occurrence of at least one sub-seismic fault in close proximity to the B1 sand reservoir. To better image the distribution of the gas-hydrate-bearing reservoir sections and associated faults, a three-dimensional (3D) vertical seismic profile was conducted in early 2019 using the distributed acoustic sensors installed as part of the Hydrate-01 STW completion. Detailed two-dimensional (2D) and 3D geologic models have been constructed to enable numerical simulations to inform the planning for potential future scientific tests of reservoir response to depressurization at the site.

Alaska↗
USGS2022

Geological reservoir characterization of a gas hydrate prospect associated with the Hydrate-01 Stratigraphic Test Well, Alaska North Slope

Geological reservoir characterization is essential for accurate evaluation of gas production performance from gas hydrate reservoirs. Particularly, the understanding of reservoir architecture and heterogeneity is of great importance since these are considered as major controls on fluid hydrodynamic and thermodynamic conditions. This study deals with well log and three-dimensional (3-D) vertical seismic profile (VSP) data acquired from the Hydrate-01 Stratigraphic Test Well within the 7-11-12 prospect, Prudhoe Bay Unit, Alaska North Slope and reports on the results of geological/geophysical evaluation related to the geological structure and reservoir properties of the 7-11-12 prospect. The structural trends of the target reservoirs, based on well correlations, are mostly consistent with the predrill prediction using the surface seismic data, and infer the existence of subseismic faults cutting through the Hydrate-01 well. The 3-D VSP data confirm a down-to-the-east normal fault that offsets the reservoir units across the Hydrate-01 well, which is concordant with the well identification of the same fault, and indicate a northeast-dipping relay structure associated with the overstepping normal faults. The edge enhancement attribute associated with discontinuity generated from the 3-D VSP data shows small faults/fractures, possibly as part of a complex fault network within the imaged normal fault system. These results reveal that the 3-D VSP data provide detailed structural information that is not present from the surface seismic data. The Hydrate-01 well log data confirm the occurrence of gas hydrate at high saturation in the two targeted sand units (B1 and D1 sands), and the comparison to a nearby pre-existing well (7-11-12 well) shows the same general trend in gas hydrate saturation as a map of seismic impedance generated from surface seismic data. The well log data also suggest that the base of gas hydrate occurrence in the Hydrate-01 and 7-11-12 wells is almost aligned at the same depth in both of the targeted B1 and D1 sand reservoirs. Especially for the D1 sand in the Hydrate-01 well, the resistivity logs show a sharp transition from high gas hydrate saturation to fully water-saturated within the D1 sand, suggesting a common gas hydrate/water contact. The results of this study will be used to construct the geological models needed for reservoir simulation studies and they can provide important insights into the geological factors that control the occurrence of gas hydrate on the Alaska North Slope.

Alaska↗
USGS2022

Virtual special issue of recent advances on gas hydrates scientific drilling in Alaska

Gas hydrate refers to a non-stoichiometric clathrate that forms spontaneously in the natural environment whenever sufficient quantities of gases of appropriate size (most commonly methane) interact with abundant water under specific conditions of temperature and pressure. (1,2) Such conditions occur wherever the shallow geothermal gradient has been suppressed by either deepwater or thick permafrost, allowing for relatively low temperatures to coexist with elevated pressures. The volume of gas hydrate on Earth is difficult to constrain, (3) but it is sufficient that gas hydrate is a meaningful potential component of (1) the long-term natural cycling of carbon, (2) the nearer term environmental changes in response to warming climates, (4) and (3) future energy supply systems. Since the initial recognition of gas hydrate as an abundant component in nature in the late 1960s, a series of scientific drilling expeditions conducted by both the Integrated Ocean Discovery Program (and successors) and national research and development programs in Canada, Japan, China, the United States, South Korea, and others (5) have explored the occurrence and nature of gas hydrates. In particular, the desire for expanded energy supply options to support the economic development and energy security for nations around the globe is currently motivating a broad range of laboratory and numerical simulation studies in support of an ongoing series of field-based scientific tests of the potential commercial viability of gas extraction from natural gas hydrate deposits. (6)

Journal of Energy & Fuels↗
USGS2024

Examining water and proppant demand, and produced water production, associated with petroleum resource development in the Eagle Ford Group, Texas

More than 20,000 horizontal wells have been drilled and hydraulically fractured in the Eagle Ford Group since the discovery well in 2008, but a considerable amount of undiscovered petroleum remains. Recently, drilled wells have been hydraulically fractured with an average of nearly 13 million gallons of water and 16 million lb of sand, yielding a million or more gallons of produced water. To inform future petroleum development in the Eagle Ford, the U.S. Geological Survey (USGS) conducted a water and proppant assessment using a geology-based approach that builds on the 2018 USGS assessment of undiscovered technically recoverable petroleum. Using probabilistic input values and a Monte Carlo simulation, we determined that production of the remaining undiscovered technically recoverable oil and gas in the Eagle Ford Group would require approximately 687,565 Mgal (millions of gallons) of water and 839,702,000,000 lb of proppant (both are mean values of output distributions). This possible future petroleum production would also include 176,817 Mgal (mean value) of produced formation water. On average, oil wells require water volumes that are approximately twice the volume of oil that will be produced, and Eagle Ford gas wells require approximately 5.21 Mgal of water per billion cubic feet of gas (bcfg). Produced formation water volumes are approximately 60% of the produced oil volume and, for gas wells, will yield approximately 1 Mgal formation water per bcfg. Understanding the water and proppant requirements associated with petroleum exploration and the resulting volume of produced water can inform decisions regarding the future of Eagle Ford development.

Texas↗
USGS2024

3-D geological modeling for numerical flow simulation studies of gas hydrate reservoirs at the Kuparuk State 7-11-12 Pad in the Prudhoe Bay Unit on the Alaska North Slope

Accurate reservoir evaluation requires reliable three-dimensional (3-D) geological models. This study conducted 3-D geological modeling for numerical flow simulation of the B1 sand gas hydrate reservoir at the Kuparuk State 7-11-12 pad, Prudhoe Bay Unit, Alaska North Slope. The model integrates well logs, core, and seismic data to address spatial heterogeneity in geological structures and reservoir properties. Two modeling types were performed: structural framework modeling and petrophysical property modeling. For structural framework modeling, seismic data and well log markers were used to reproduce subsurface structures characterized by a normal fault system. A volume-based modeling algorithm and stair-step gridding were applied. The resulting 3-D model comprised 2,640,000 grid cells across 264 layers, including seven fault grids. For petrophysical property modeling, total porosity was initially modeled using sequential Gaussian simulation with collocated cokriging. To reproduce the upward coarsening of the B1 sand, upscaled log-derived total porosity and a 3-D trend depicting total porosity variation were used as primary and secondary data, respectively. Gas hydrate saturation distribution was modeled similarly, with secondary data from estimated porosity distribution and seismic-derived acoustic impedance map enhancing accuracy. Results indicate higher gas hydrate saturation in the upper part of the B1 sand and areas with higher acoustic impedance. Intrinsic permeability was modeled from the total porosity and clay-bound water volume, and effective permeability was derived from the gas hydrate saturation and intrinsic permeability distributions based on the “Tokyo model”. Effective permeability distributions were influenced by the total porosity, gas hydrate saturation, and intrinsic permeability. Within the same layer, higher gas hydrate saturation leads to decreased effective permeability. In total, 100 sets of multiple scenarios were prepared, providing input data for dynamic flow simulations to evaluate the effects of lateral heterogeneity in reservoir properties and the hydraulic characteristics of faults on production behavior for preassessment before the long-term production test.

Alaska↗
USGS2015

Detailed description of oil shale organic and mineralogical heterogeneity via fourier transform infrared mircoscopy

Mineralogical and geochemical information on reservoir and source rocks is necessary to assess and produce from petroleum systems. The standard methods in the petroleum industry for obtaining these properties are bulk measurements on homogenized, generally crushed, and pulverized rock samples and can take from hours to days to perform. New methods using Fourier transform infrared (FTIR) spectroscopy have been developed to more rapidly obtain information on mineralogy and geochemistry. However, these methods are also typically performed on bulk, homogenized samples. We present a new approach to rock sample characterization incorporating multivariate analysis and FTIR microscopy to provide non-destructive, spatially resolved mineralogy and geochemistry on whole rock samples. We are able to predict bulk mineralogy and organic carbon content within the same margin of error as standard characterization techniques, including X-ray diffraction (XRD) and total organic carbon (TOC) analysis. Validation of the method was performed using two oil shale samples from the Green River Formation in the Piceance Basin with differing sedimentary structures. One sample represents laminated Green River oil shales, and the other is representative of oil shale breccia. The FTIR microscopy results on the oil shales agree with XRD and LECO TOC data from the homogenized samples but also give additional detail regarding sample heterogeneity by providing information on the distribution of mineral phases and organic content. While measurements for this study were performed on oil shales, the method could also be applied to other geological samples, such as other mudrocks, complex carbonates, and soils.

Energy & Fuels↗
USGS2015

Extraction of hydrocarbons from high-maturity Marcellus Shale using supercritical carbon dioxide

Shale is now commonly exploited as a hydrocarbon resource. Due to the high degree of geochemical and petrophysical heterogeneity both between shale reservoirs and within a single reservoir, there is a growing need to find more efficient methods of extracting petroleum compounds (crude oil, natural gas, bitumen) from potential source rocks. In this study, supercritical carbon dioxide (CO 2 ) was used to extract n -aliphatic hydrocarbons from ground samples of Marcellus shale. Samples were collected from vertically drilled wells in central and western Pennsylvania, USA, with total organic carbon (TOC) content ranging from 1.5 to 6.2 wt %. Extraction temperature and pressure conditions (80°C and 21.7 MPa, respectively) were chosen to represent approximate in situ reservoir conditions at sample depth (1920–2280 m). Hydrocarbon yield was evaluated as a function of sample matrix particle size (sieve size) over the following size ranges: 1000–500 μm, 250–125 μm, and 63–25 μm. Several methods of shale characterization including Rock-Eval II pyrolysis, organic petrography, Brunauer–Emmett–Teller surface area, and X-ray diffraction analyses were also performed to better understand potential controls on extraction yields. Despite high sample thermal maturity, results show that supercritical CO 2 can liberate diesel-range ( n -C 11 through n -C 21 ) n -aliphatic hydrocarbons. The total quantity of extracted, resolvable n -aliphatic hydrocarbons ranges from approximately 0.3 to 12 mg of hydrocarbon per gram of TOC. Sieve size does have an effect on extraction yield, with highest recovery from the 250–125 μm size fraction. However, the significance of this effect is limited, likely due to the low size ranges of the extracted shale particles. Additional trends in hydrocarbon yield are observed among all samples, regardless of sieve size: 1) yield increases as a function of specific surface area ( r 2 = 0.78); and 2) both yield and surface area increase with increasing TOC content ( r 2 = 0.97 and 0.86, respectively). Given that supercritical CO 2 is able to mobilize residual organic matter present in overmature shales, this study contributes to a better understanding of the extent and potential factors affecting the extraction process.

Pennsylvania↗
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

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.

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