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At least 55 records · Page 3Linked to original sources
USGS2012

Gulf of Mexico Gas Hydrate Joint Industry Project Leg II logging-while-drilling data acquisition and analysis

One of the objectives of the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II (GOM JIP Leg II) was the collection of a comprehensive suite of logging-while-drilling (LWD) data within gas-hydrate-bearing sand reservoirs in order to make accurate estimates of the concentration of gas hydrates under various geologic conditions and to understand the geologic controls on the occurrence of gas hydrate at each of the sites drilled during this expedition. The LWD sensors just above the drill bit provided important information on the nature of the sediments and the occurrence of gas hydrate. There has been significant advancements in the use of downhole well-logging tools to acquire detailed information on the occurrence of gas hydrate in nature: From using electrical resistivity and acoustic logs to identify gas hydrate occurrences in wells to where wireline and advanced logging-while-drilling tools are routinely used to examine the petrophysical nature of gas hydrate reservoirs and the distribution and concentration of gas hydrates within various complex reservoir systems. Recent integrated sediment coring and well-log studies have confirmed that electrical resistivity and acoustic velocity data can yield accurate gas hydrate saturations in sediment grain supported (isotropic) systems such as sand reservoirs, but more advanced log analysis models are required to characterize gas hydrate in fractured (anisotropic) reservoir systems. In support of the GOM JIP Leg II effort, well-log data montages have been compiled and presented in this report which includes downhole logs obtained from all seven wells drilled during this expedition with a focus on identifying and characterizing the potential gas-hydrate-bearing sedimentary section in each of the wells. Also presented and reviewed in this report are the gas-hydrate saturation and sediment porosity logs for each of the wells as calculated from available downhole well logs.

Gulf Of Mexico↗
USGS2019

Formation pressure and fluid flow measurements in marine gas hydrate reservoirs, NGHP-02 expedition, offshore India

Open Hole Modular Dynamic Testing (MDT) measurements were conducted in a gas hydrate-bearing sand-rich reservoir offshore India during the National Gas Hydrate Program 02 (NGHP-02) Expedition. The primary goal of this test was to obtain effective reservoir petrophysical properties in the presence of gas hydrates. The test plan included a series of pre-hydrate dissociation flow and build-up (shut-in) tests, and an attempt to dissociate gas hydrate in a sand-rich reservoir by depressurization to collect formation fluid samples and to further characterize in situ gas hydrate stability conditions. Schlumberger’s wireline MDT tool was used in a dual-packer configuration to isolate the formation being tested. This paper presents the results of the open hole MDT measurements that were conducted in Hole NGHP-02-23-C in Krishna-Godavari Basin at a water depth of 2553.5 m. The MDT dual packer test was conducted in 27 cm (10.63 in) diameter open hole section of the borehole within a 1-m interval isolated between two inflatable packers with the midpoint of the test interval at 2853.0 meter below rig floor (mbrf) (271.0 meter below sea floor (mbsf)). This was the first gas hydrate MDT test ever conducted in ultradeep water to characterize a gas hydrate reservoir system. Pre-hydrate dissociation testing was performed with a drawdown period (depressurization) of 20 minutes followed by a build-up (shut-in) of 20 minutes. The measured formation pressure was 4090.7 psia and the formation fluid (i.e., water) mobility was calculated at 1.98 mD/cP. During the second dissociation phase of the same test a maximum pressure drawdown of 840 psia was achieved; however, falling short of the 1120 psia drawdown required for dissociation. During the dissociation test the flow line pressure stabilized at a flowing pressure of 3250 psia which can be attributed to the relatively high mobility of the free water phase in the hydrate-bearing reservoir. Good quality formation pressure and near well bore mobility data was acquired that yielded a “high confidence” reservoir effective radial permeability-thickness product of 0.2 mD.m (or a horizontal effective permeability of 0.1 mD assuming a reservoir thicknees of 1.8 m) using pressure transient analysis (radial flow regime was achieved) despite unstable borehole conditions and complex operations in these shallow unconsolidated sedimentary sections.

Journal of Marine and Petroleum Geology↗
USGS2020

Characterization of the unconventional Tuscaloosa marine shale reservoir in southwestern Mississippi, USA: Insights from optical and SEM petrography

This study presents new optical petrography and electron microscopy data, interpreted in the context of previously published petrophysical, geochemical, and mineralogical data, to further characterize the Tuscaloosa marine shale (TMS) as an unconventional reservoir in southwestern Mississippi. The basal high resistivity zone has a higher proportion of Type II sedimentary organic matter than the overlying TMS, indicating it is more prone to oil generation. Optical petrography and electron microscopy reveal a heterogeneous clay matrix with ubiquitous pyrite grains, quartz, feldspar, glaucony, foraminifera, shell fragments, and rarer occurrences of apatite and crinoid fragments as well as liptinite, alginite, inertinite, and vitrinite. Our petrographic observations suggest that higher abundances of detrital quartz grains coupled with minimal authigenic cements result in higher porosity and permeability. However, the TMS is also more clay-rich than other unconventional shale oil and gas plays, which can impair the effectiveness of hydraulic fracture stimulation. Thin section observations reveal alternating clay and calcium carbonate laminae that are interpreted to reflect changes in sediment flux. Planktonic foraminifera indicate an overlying oxygenated water column while benthic inoceramid fragments and pervasive authigenic pyrite suggest anoxic or dysoxic bottom water conditions. Apatite fragments in thin section suggest mixing events and an influx of nutrient-rich sediments. Overall, these observations suggest that a variety of paleodepositional environments occurred in the TMS and the lithofacies diversity resulting from these small-scale depositional cycles makes it difficult to determinatively identify areas conducive to enhanced economic hydrocarbon recovery.

Mississippi, Lousianna↗
USGS2021

Multiple physical properties of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Knowledge of the petrophysical and geomechanical properties of gas hydrate-bearing sediments is essential for predicting reservoir responses to gas production from gas hydrate reservoirs. In December 2018, Stratigraphic Test Well Hydrate-01 was drilled in the western part of the Prudhoe Bay Unit, Alaska North Slope, as part of the technical planning effort for a future long-term gas hydrate production test. Side-wall pressure coring was conducted to recover gas hydrate-bearing sediments from two reservoir sections named Unit B and Unit D. A total of 34 cores were successfully recovered during five runs of a wireline deployed pressure corer, and a total of 17 cores were preserved for advanced laboratory analysis. The samples were frozen inside the pressure core autoclave by liquid nitrogen while at high pressure before being removed and stored under liquid nitrogen at atmospheric pressure. High-resolution X-ray computed tomography showed the samples were high-quality, with undisturbed lithological layers. The Unit B and D sediments were categorized as sand or sandy silt with high hydrate saturation. Gas compositions suggest the hydrates formed with thermogenic and microbial mixed gases. Permeability tests and triaxial compression tests were conducted on the hydrate-bearing sediments. Low strengthening and high permeability at hydrate saturation S h > 80% were observed. There was a small permeability reduction during the triaxial compression tests owing to porosity loss with increasing effective stress in the highly permeable sandy sediment after hydrate dissociation. The apparent minimal changes in porosity and permeability during the tests were due to the low-clay content and low compressibility of the quartz sand grains in the recovered cores. X-ray powder diffraction and thermal conductivity analysis also suggested a high quartz content for the analyzed samples.

Alaska↗
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

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

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↗
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↗
USGS2007

Geoelectrical evidence of bicontinuum transport in groundwater

Bicontinuum models and rate-limited mass transfer (RLMT) explain complex transport behavior (e.g., long tailing and rebound) in heterogeneous geologic media, but experimental verification is problematic because geochemical samples represent the mobile component of the pore space. Here, we present geophysical evidence of RLMT at the field scale during an aquifer-storage and recovery experiment in a fractured limestone aquifer in Charleston, South Carolina. We observe a hysteretic relation between measurements of porefluid conductivity and bulk electrical conductivity; this hysteresis contradicts advective-dispersive transport and the standard petrophysical model relating pore-fluid and bulk conductivity, but can be explained by considering bicontinuum transport models that include first-order RLMT. Using a simple numerical model, we demonstrate that geoelectrical measurements are sensitive to bicontinuum transport and RLMT parameters, which are otherwise difficult to infer from direct, hydrologic measurements.

South Carolina↗
USGS2009

Anatomy of the dead sea transform from lithospheric to microscopic scale

Fault zones are the locations where motion of tectonic plates, often associated with earthquakes, is accommodated. Despite a rapid increase in the understanding of faults in the last decades, our knowledge of their geometry, petrophysical properties, and controlling processes remains incomplete. The central questions addressed here in our study of the Dead Sea Transform (DST) in the Middle East are as follows: (1) What are the structure and kinematics of a large fault zone? (2) What controls its structure and kinematics? (3) How does the DST compare to other plate boundary fault zones? The DST has accommodated a total of 105 km of leftlateral transform motion between the African and Arabian plates since early Miocene (???20 Ma). The DST segment between the Dead Sea and the Red Sea, called the Arava/ Araba Fault (AF), is studied here using a multidisciplinary and multiscale approach from the ??m to the plate tectonic scale. We observe that under the DST a narrow, subvertical zone cuts through crust and lithosphere. First, from west to east the crustal thickness increases smoothly from 26 to 39 km, and a subhorizontal lower crustal reflector is detected east of the AF. Second, several faults exist in the upper crust in a 40 km wide zone centered on the AF, but none have kilometer-size zones of decreased seismic velocities or zones of high electrical conductivities in the upper crust expected for large damage zones. Third, the AF is the main branch of the DST system, even though it has accommodated only a part (up to 60 km) of the overall 105 km of sinistral plate motion. Fourth, the AF acts as a barrier to fluids to a depth of 4 km, and the lithology changes abruptly across it. Fifth, in the top few hundred meters of the AF a locally transpressional regime is observed in a 100-300 m wide zone of deformed and displaced material, bordered by subparallel faults forming a positive flower structure. Other segments of the AF have a transtensional character with small pull-aparts along them. The damage zones of the individual faults are only 5-20 m wide at this depth range. Sixth, two areas on the AF show mesoscale to microscale faulting and veining in limestone sequences with faulting depths between 2 and 5 km. Seventh, fluids in the AF are carried downward into the fault zone. Only a minor fraction of fluids is derived from ascending hydrothermal fluids. However, we found that on the kilometer scale the AF does not act as an important fluid conduit. Most of these findings are corroborated using thermomechanical modeling where shear deformation in the upper crust is localized in one or two major faults; at larger depth, shear deformation occurs in a 20-40 km wide zone with a mechanically weak decoupling zone extending subvertically through the entire lithosphere. Copyright 2009 by the American Geophysical Union.

Reviews of Geophysics↗
USGS2005

Geophysical monitoring of a field-scale biostimulation pilot project

The USGS conducted a geophysical investigation in support of a U.S. Naval Facilities Engineering Command, Southern Division field‐scale biostimulation pilot project at Anoka County Riverfront Park (ACP), downgradient of the Naval Industrial Reserve Ordnance Plant, Fridley, Minnesota. The goal of the pilot project is to evaluate subsurface injection of vegetable oil emulsion (VOE) to stimulate microbial degradation of chlorinated hydrocarbons. To monitor the emplacement and movement of the VOE and changes in water chemistry resulting from VOE dissolution and/or enhanced biological activity, the USGS acquired cross‐hole radar zero‐offset profiles, traveltime tomograms, and borehole geophysical logs during five site visits over 1.5 years. Analysis of pre‐ and postinjection data sets using petrophysical models developed to estimate VOE saturation and changes in total dissolved solids provides insights into the spatial and temporal distribution of VOE and ground water with altered chemistry. Radar slowness‐difference tomograms and zero‐offset slowness profiles indicate that the VOE remained close to the injection wells, whereas radar attenuation profiles and electromagnetic induction logs indicate that bulk electrical conductivity increased downgradient of the injection zone, diagnostic of changing water chemistry. Geophysical logs indicate that some screened intervals were located above or below zones of elevated dissolved solids; hence, the geophysical data provide a broader context for interpretation of water samples and evaluation of the biostimulation effort. Our results include (1) demonstration of field and data analysis methods for geophysical monitoring of VOE biostimulation and (2) site‐specific insights into the spatial and temporal distributions of VOE at the ACP.

Minnesota↗
USGS2011

Hydrogeophysical methods for analyzing aquifer storage and recovery systems

Hydrogeophysical methods are presented that support the siting and monitoring of aquifer storage and recovery (ASR) systems. These methods are presented as numerical simulations in the context of a proposed ASR experiment in Kuwait, although the techniques are applicable to numerous ASR projects. Bulk geophysical properties are calculated directly from ASR flow and solute transport simulations using standard petrophysical relationships and are used to simulate the dynamic geophysical response to ASR. This strategy provides a quantitative framework for determining site‐specific geophysical methods and data acquisition geometries that can provide the most useful information about the ASR implementation. An axisymmetric, coupled fluid flow and solute transport model simulates injection, storage, and withdrawal of fresh water (salinity ∼500 ppm) into the Dammam aquifer, a tertiary carbonate formation with native salinity approximately 6000 ppm. Sensitivity of the flow simulations to the correlation length of aquifer heterogeneity, aquifer dispersivity, and hydraulic permeability of the confining layer are investigated. The geophysical response using electrical resistivity, time‐domain electromagnetic (TEM), and seismic methods is computed at regular intervals during the ASR simulation to investigate the sensitivity of these different techniques to changes in subsurface properties. For the electrical and electromagnetic methods, fluid electric conductivity is derived from the modeled salinity and is combined with an assumed porosity model to compute a bulk electrical resistivity structure. The seismic response is computed from the porosity model and changes in effective stress due to fluid pressure variations during injection/recovery, while changes in fluid properties are introduced through Gassmann fluid substitution.

Groundwater↗
USGS2009

Structural and geochemical characteristics of faulted sediments and inferences on the role of water in deformatiion, Rio Grande Rift, New Mexico

The San Ysidro fault is a spectacularly exposed normal fault located in the northwestern Albuquerque Basin of the Rio Grande Rift. This intrabasin fault is representative of many faults that formed in poorly lithified sediments throughout the rift. The fault is exposed over nearly 10 km and accommodates nearly 700 m of dip slip in subhorizontal, siliciclastic sediments. The extent of the exposure facilitates study of along-strike variations in deformation mechanisms, archi tecture, geochemistry, and permeability. The fault is composed of structural and hydrogeologic components that include a clay-rich fault core, a calcite-cemented mixed zone, and a poorly developed damage zone primarily consisting of deformation bands. Structural textures suggest that initial deformation in the fault occurred at low temperature and pressure, was within the paleosaturated zone of the evolving Rio Grande Rift, and was dominated by particulate flow. Little geochemical change is apparent across the fault zone other than due to secondary processes. The lack of fault-related geochemical change is interpreted to reflect the fundamental nature of water-saturated, particulate fl ow. Early mechanical entrainment of low-permeability clays into the fault core likely caused damming of groundwater flow on the up-gradient, footwall side of the fault. This may have caused a pressure gradient and flow of calcite-saturated waters in higher-permeability, fault-entrained siliciclastic sediments, ultimately promoting their cementation by sparry calcite. Once developed, the cemented and clay-rich fault has likely been, and continues to be, a partial barrier to cross-fault groundwater flow, as suggested by petrophysical measurements. Aeromagnetic data indicate that there may be many more unmapped faults with similar lengths to the San Ysidro fault buried within Rio Grande basins. If these buried faults formed by the same processes that formed the San Ysidro fault and have persistent low-permeability cores and cemented mixed zones, they could compartmentalize the basin-fill aquifers more than is currently realized, particularly if pumping stresses continue to increase in response to population growth. ?? 2009 Geological Society of America.

Geological Society of America Bulletin↗
USGS2014

Seismic evidence for a crustal magma reservoir beneath the upper east rift zone of Kilauea volcano, Hawaii

An anomalous body with low Vp (compressional wave velocity), low Vs (shear wave velocity), and high Vp/Vs anomalies is observed at 8–11 km depth beneath the upper east rift zone of Kilauea volcano in Hawaii by simultaneous inversion of seismic velocity structure and earthquake locations. We interpret this body to be a crustal magma reservoir beneath the volcanic pile, similar to those widely recognized beneath mid-ocean ridge volcanoes. Combined seismic velocity and petrophysical models suggest the presence of 10% melt in a cumulate magma mush. This reservoir could have supplied the magma that intruded into the deep section of the east rift zone and caused its rapid expansion following the 1975 M7.2 Kalapana earthquake.

Hawaii↗
USGS2006

Effects of spatially variable resolution on field-scale estimates of tracer concentration from electrical inversions using Archie's law

Two important mechanisms affect our ability to estimate solute concentrations quantitatively from the inversion of field-scale electrical resistivity tomography (ERT) data: (1) the spatially variable physical processes that govern the flow of current as well as the variation of physical properties in space and (2) the overparameterization of inverse models, which requires the imposition of a smoothing constraint (regularization) to facilitate convergence of the inverse solution. Based on analyses of field and synthetic data, we find that the ability of ERT to recover the 3D shape and magnitudes of a migrating conductive target is spatially variable. Additionally, the application of Archie's law to tomograms from field ERT data produced solute concentrations that are consistently less than 10% of point measurements collected in the field and estimated from transport modeling. Estimates of concentration from ERT using Archie's law only fit measured solute concentrations if the apparent formation factor is varied with space and time and allowed to take on unreasonably high values. Our analysis suggests that the inability to find a single petrophysical relation in space and time between concentration and electrical resistivity is largely an effect of two properties of ERT surveys: (1) decreased sensitivity of ERT to detect the target plume with increasing distance from the electrodes and (2) the smoothing imprint of regularization used in inversion.

Geophysics↗
USGS2019

Geophysical mapping of plume discharge to surface water at a crude oil spill site: Inversion versus machine learning

The interpretation of geophysical survey results to answer hydrologic, engineering, and geologic questions is critical to diverse problems for management of water, energy, and mineral resources. Although geophysical images provide valuable qualitative insight into subsurface architecture and conditions, translating geophysical images into quantitative information (e.g., saturation, concentration, and hydraulic properties) often involves substantial nonuniqueness and uncertainty owing to the limited resolution of geophysical imaging and uncertainty in petrophysical relations. We have developed a machine-learning approach to address these challenges in the context of a field-based investigation to map zones where a hydrocarbon plume was discharging to surface water at the National Crude Oil Spill Fate and Natural Attenuation Research Site in Bemidji, Minnesota, USA. The two-step approach combines multiple types of geophysical and direct information and effectively bypasses inversion and its associated assumptions. Integrating multifrequency electromagnetic induction, ground-penetrating radar, and fluid-sampling data, we first identify discharge zones and second estimate specific conductance versus depth. Compared with conventional inversion results, the machine-learning results (1) directly address the study objectives (delineating the discharge zones); (2) better extract depth-dependent information from the data, for which sensitivity diminishes rapidly with depth; and (3) quantify the uncertainty of the predictions (i.e., discharge versus nondischarge zones), rather than the uncertainty of the geophysical estimates (i.e., the standard error of estimation for the logarithm of electrical conductivity).

Minnesota↗
USGS2021

Integrated geophysical imaging of rare-earth-element-bearing iron oxide-apatite deposits in the eastern Adirondack Highlands, New York

The eastern Adirondack Highlands of northern New York host dozens of iron oxide-apatite (IOA) deposits containing magnetite and rare earth element (REE)-bearing apatite. We use new aeromagnetic, aeroradiometric, ground gravity, and sample petrophysical and geochemical data to image and understand these deposits and their geologic framework. Aeromagnetic total field data reflect highly magnetic leucogranite host rock and major structures that likely served as fluid conduits for the hydrothermal system. Bandpass filtering of the aeromagnetic data reveals individual deposits that were verified in the field or from historical records. A three-dimensional inversion for magnetic susceptibility images these deposits at depth, allowing inference of plunge directions and relative size. Radiometric data highlight variations in the surface geology and several large tailings piles that contain REE-bearing apatite. Within the host rock, eTh (equivalent Th), K and the eTh/K ratio are variable with high eTh/K near several of the IOA deposits. Areas with elevated K or low eTh/K representing potassic alteration appear to be rare; instead elevated eTh/K ratios likely reflect widespread sodic alteration overprinting potassic alteration. Bouguer gravity anomalies show limited correspondence to the surface geology, radiometric data, or magnetic data, but do exhibit ~10-km wide highs in areas where deposits are observed. Two-dimensional forward models of the gravity and magnetic data show that deeper dense material beneath the leucogranite is quantitatively feasible. If these dense rocks represent intrusions that were emplaced or still cooling at the time of mineralization, they may have served as a heat source that helped to drive the hydrothermal system. Combining datasets, we find that deposits occur towards the distal ends of major structures within the host leucogranite and mostly above gravity highs. The geophysical modeling thus suggests that IOA deposits formed in structural, thermal, and chemical traps near the distal ends of the hydrothermal system.

New York↗