Geology Reports⌕ Search

SEARCH · Geology Reports

Results for “Marine and Petroleum Geology”

Search indexed USGS publications on groundwater, aquifers, geologic maps, mineral resources and earthquakes. Explore source records by subject and place.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 127 records · Page 7Linked to original sources
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↗
USGS2019

Insights from Rock-Eval analysis on the influence of sample weight on hydrocarbon generation from Lower Permian organic-matter rich rocks, West Bokaro basin, India

Among the different Rock-Eval parameters, the hydrocarbons released under S2 peak of Rock-Eval is of significance as it indicates the residual hydrocarbon content of the rock. Further, through its relationship with TOC content, it helps in calculating hydrogen indices (HI) which helps in understanding the type of organic-matter present in a rock [HI= (S2/TOC)*100]. The present study documents the role of sample weight/amount used for analysis on Rock-Eval S2 parameter for unconventional source-rock characterization. For the purpose of study, a vitrain-band sample type (manually isolated from a coal), a high-TOC shale sample type, and a carbonaceous shale sample type, were analyzed at two different particle sizes (viz. 1mm-500 microns and 212-75 microns) and different sample weights (5-15 mg for organic-matter rich rocks, and 30-60 mg for shale) using a Rock-Eval basic cycle (heating rate at 25 °C/min). Although S2 is reported as mg HC/ g rock, with increase in sample weight, an increase in hydrocarbons released under S2 peak of Rock-Eval was observed for all three sample types for both the particle sizes. The observations were further validated using a Norwegian geochemical standard (JR-1). Further, all the samples were reanalyzed by conducting pyrolysis experiments at a lower heating rate of 5 °C/min. The impact of sample weight on S2 and hydrogen index (HI) was observed to be more pronounced for the JR-1 standard (higher hydrocarbon yield) than the Types III-IV organic-matter bearing rocks. It thus calls for interpreters to be aware of the influence of mass of organic-matter on hydrocarbon generation, and to monitor the maximum S2 values of organic-matter bearing rocks, within the Flame Ionization Detector (FID) detection limits. Further, it is recommended that for Type III organic-matter bearing rocks with TOC content>20 wt %, elemental analysis should be used to derive atomic H/C and O/C ratios for Van Krevelen diagram-based kerogen typing.

West Bokaro basin↗
USGS2020

Organic petrography of Leonardian (Wolfcamp A) mudrocks and carbonates, Midland Basin, Texas: The fate of oil-prone sedimentary organic matter in the oil window

To better understand evolution of oil-prone sedimentary organic matter to petroleum and expulsion from source rock, we evaluated organic petrographic features of Leonardian Wolfcamp A repetitive siliceous and calcareous mudrock and fine-grained carbonate lithofacies cycles occurring in the R. Ricker #1 core from Reagan County, Midland Basin, Texas. The objectives of the petrographic investigation were to estimate thermal maturity, identify organic matter types and abundances, and identify the presence or absence of migrated hydrocarbons in organic-lean carbonate layers. An integrated analytical program included geochemical screening [total organic carbon (TOC) content by LECO, programmed pyrolysis by hydrocarbon analyzer with kinetics (HAWK) including analysis of solvent-extracted samples], X-ray diffraction mineralogy, organic petrography, scanning electron microscopy with energy dispersive spectroscopy (SEM-EDS) including correlative light and electron microscopy (CLEM), and micro-Fourier transform infrared spectroscopy (μ-FTIR) analyses of solid bitumen. The data indicate all samples are early to middle oil window thermal maturity with solid bitumen reflectance (BR o ) values of 0.55–0.86% and T max of 440–455 °C. Organic matter is predominantly solid bitumen (as identified by optical microscopy) in all lithofacies with minor contributions from inertinite. Solid bitumen abundance decreases from siliceous mudrock (TOC >3.0 wt%) to calcareous mudrock (TOC 1.0 to 3.0 wt%) to fine-grained carbonate (TOC <1.0 wt%) lithofacies. Interpretations of petrographic data suggest siliceous and calcareous mudrocks are source rock lithofacies and contain solid bitumen (with petroleum generation potential) that is residual (what remains) from conversion of an original Type II sedimentary organic matter. In turn, fine-grained carbonates are interpreted as reservoir lithofacies which contained little or no original oil-prone sedimentary organic matter and at present-day contain only a minor component of migrated solid petroleum sourced from adjacent siliceous and calcareous mudrock lithofacies. This work helps to document petroleum generation and migration processes, improve unconventional reservoir characterization and better define areas of oil window thermal maturity in an area critical to United States hydrocarbon production.

Texas↗
USGS2020

Testing reproducibility of vitrinite and solid bitumen reflectance measurements in North American unconventional source-rock reservoir petroleum systems

An interlaboratory study (ILS) was conducted to test reproducibility of vitrinite and solid bitumen reflectance measurements in six mudrock samples from United States unconventional source-rock reservoir petroleum systems. Samples selected from the Marcellus, Haynesville, Eagle Ford, Barnett, Bakken and Woodford are representative of resource plays currently under exploitation in North America. All samples are from marine depositional environments, are thermally mature (T max >445 °C) and have moderate to high organic matter content (2.9–11.6 wt% TOC). Their organic matter is dominated by solid bitumen, which contains intraparticle nano-porosity. Visual evaluation of organic nano-porosity (pore sizes < 100 nm) via SEM suggests that intraparticle organic nano-pores are most abundant in dry gas maturity samples and less abundant at lower wet gas/condensate and peak oil maturities. Samples were distributed to ILS participants in forty laboratories in the Americas, Europe, Africa and Australia; thirty-seven independent sets of results were received. Mean vitrinite reflectance (VR o ) values from all ILS participants range from 0.90 to 1.83% whereas mean solid bitumen reflectance (BR o ) values range from 0.85 to 2.04% (no outlying values excluded), confirming the thermally mature nature of all six samples. Using multiple statistical approaches to eliminate outlying values, we evaluated reproducibility limit R, the maximum difference between valid mean reflectance results obtained on the same sample by different operators in different laboratories using different instruments. Removal of outlying values where the individual signed multiple of standard deviation was >1.0 produced lowest R values, generally ≤0.5% (absolute reflectance), similar to a prior ILS for similar samples. Other traditional approaches to outlier removal (outside mean ± 1.5*interquartile range and outside F10 to F90 percentile range) also produced similar R values. Standard deviation values < 0.15*(VR o or BR o ) reduce R and should be a requirement of dispersed organic matter reflectance analysis. After outlier removal, R values were 0.1%–0.2% for peak oil thermal maturity, about 0.3% for wet gas/condensate maturity and 0.4%–0.5% for dry gas maturity. That is, these R values represent the uncertainty (in absolute reflectance) that users of vitrinite and solid bitumen reflectance data should assign to any one individual reported mean reflectance value from a similar thermal maturity mudrock sample. R values of this magnitude indicate a need for further standardization of reflectance measurement of dispersed organic matter. Furthermore, these R values quantify realistic interlaboratory measurement dispersion for a difficult but critically important analytical technique necessary for thermal maturity determination in the source-rock reservoirs of unconventional petroleum systems.

Marine and Petroleum Geology↗
USGS2020

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

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

Marine and Petroleum Geology↗
USGS2020

Trends in thermal maturity indicators for the organic sulfur-rich Eagle Ford Shale

Thermal maturity is critical to evaluate petroleum systems and to interpret biomarker results for paleoenvironmental and geobiology studies. Many thermal maturity indices were developed for marine source rocks containing type II kerogen, but their behavior in organic sulfur-rich source rocks requires more investigation. Here, we present geochemical analyses of whole and extracted rock, isolated kerogens, and extractable organic matter across a natural thermal maturity transect of the Upper Cretaceous Eagle Ford Shale to evaluate the behavior of maturity parameters in organic sulfur-rich source rocks. The samples contain similar mineralogy and trace element composition, minimizing potential facies effects on thermal maturity parameters. Atomic H/C ratios of isolated kerogens, extractable organic matter yield, and programmed pyrolysis results show that the samples range from the pre-oil through dry gas generation windows. Programmed pyrolysis data and kerogen elemental ratios show that the immature samples host both type IIS (atomic Sorg/C > 0.04) and sulfur-rich type II kerogen (kerogen Sorg/C: 0.032 to 0.045) while the samples with lower kerogen Sorg/C ratios (kerogen Sorg/C < 0.03) are more mature. The vitrinite reflectance values corresponding to the onset of oil generation in the Eagle Ford are comparable to other type II petroleum systems. Likewise, the organic sulfur-rich Eagle Ford follows a similar hydrogen index and kerogen H/C trend as other marine type II source rocks. Hopane and sterane stereoisomer maturity ratios are anomalously elevated at low thermal maturities, so they should not be applied in organic sulfur-rich petroleum systems to infer thermal maturity. However, some biomarker ratios, including those that are more commonly used as source parameters, strongly track thermal maturity in this case study with limited facies variability.

Texas↗
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↗
USGS2021

A review of sand detachment in modern deep marine environments: Analogues for upslope stratigraphic traps

Isolated, detached sands provide opportunities for large-volume stratigraphic traps in many deepwater petroleum systems. Here we provide a review of the different types of sandbody detachments based on published data from the modern-day seafloor and recent (generally Quaternary-present), shallow-buried strata. Detachment mechanisms can be classified based on their timing of formation relative to deposition of the detached sandbody as well as their process of formation. Syndepositional detachment mechanisms include flow transformation associated with slope failure (Class 1), turbidity current erosion (Class 2), and contourite deposition (Class 3). Post-depositional detachment is related to subsequent erosive processes and truncation of the pre-existing sandbody, either by submarine channels (Class 4), mass-transport events (Class 5), post-depositional sliding or faulting (Class 6) or bottom currents (Class 7). Examples of each of these mechanisms are identified on the modern seafloor, and show that detached sandbodies can form at different locations along the continental slope and rise (from upper slope to basin floor), and between or within different architectural elements (i.e., canyon, channels and lobes). This variation in formation style results in detached sands of highly variable sizes (tens to hundreds of kilometres) and geometries across and along the depositional profile, which are dependent upon the erosive and/or depositional processes involved, as well as the seafloor topography of the area in question. Whilst modern seafloor systems may not always represent the final stratigraphic architecture in the subsurface, they provide important insights into the development of detached sandbodies and therefore serve as potential analogues for subsurface stratigraphic traps.

Marine and Petroleum Geology↗
USGS2021

Hydrous pyrolysis of New Albany Shale: A study examining maturation changes and porosity development

The characterization of nanoscale organic structures has improved our understanding of porosity development within source-rock reservoirs, but research linking organic porosity evolution to thermal maturity has generated conflicting results. To better understand this connection, an immature (0.25% solid bitumen reflectance; BR o ) sample of the New Albany Shale was used in four isothermal hydrous pyrolysis (HP) experiment sequences at 300°, 320°, 340°, and 370°C, with residues collected periodically for a maximum of 103 days. The HP residues, along with the original immature sample and two naturally matured (1.49 and 1.56% BR o ) New Albany Shale samples were analyzed for organic petrology, total organic carbon (TOC) content, and organic porosity evaluation using correlative light and electron microscopy (CLEM). All of the HP series increased in thermal maturity with increasing duration of pyrolysis, though reflectance for each series plateaued within 25 days of maturation. Initially, TOC in the HP residues decreases (from 14.24 wt. %) with increasing thermal maturity until ∼1.0% BR o where TOC remains at ∼9–10 wt. % for all remaining residues. Qualitative CLEM observations within the 50–100 day 300° and 340°C HP sequences (0.95–1.70% BR o ), and the naturally matured samples, develop organic porosity in smaller (<5 μm in diameter), void-filling solid bitumen that occurs in spaces between clays and other fine-grained minerals. The 370°C HP residues developed significant organic porosity, relative to the other HP temperature series in all solid bitumen accumulations regardless of size. Overall, the study indicates that temperature and duration of artificial maturation play an important role in the abundance of pores in the HP residues. This work expands on our understanding of the conditions needed for the generation and development of organic porosity in the New Albany Shale and potentially in other marine source-rock petroleum systems.

Illinois, Indiana↗
USGS2022

Geochemical characterization of natural gases in the pre-salt section of the Santos Basin (Brazil) focused on hydrocarbons and volatile organic sulfur compounds

The objective of this work is to characterize the geochemistry of a suite of natural gas samples from five fields in order to improve the understanding of the lacustrine petroleum system of the pre-salt section from the Santos Basin (Brazil). Additionally, the distribution of volatile organic sulfur compounds (VOSC) in petroleum reservoirs was examined to investigate possible applications to petroleum systems assessments. The hydrocarbon gases were generated by thermogenic processes associated with the oil window. The 13 C-enriched values for C 1 (>−40‰) were interpreted as an organic source signature rather than an indication of thermal maturity, except for the oil occurrence (Field B), where a different fluid charge mainly composed of methane and CO 2 from a minor external kitchen area in the Santos Basin was identified. The molecular composition and the carbon and hydrogen isotopic data of the hydrocarbon gases, when combined with the VOSC molecular compositional data, allow the identification of four gas families associated with different kitchens and/or migrations pathways. The total VOSC concentrations range from 0.7 to 23.9 ppm by volume (ppmV). The organic sulfides are mainly composed of carbonyl sulfide (COS) and diethyl sulfide. The main thiol compound is ethanethiol. The cyclic VOSC are primarily composed of thiophene, with a negligible amount of branched thiophenes (<0.1 ppmV). H2S showed a strong positive Pearson's correlation with COS and methanethiol (MeSH) concentrations (r = 0.943 and 0.807, respectively). This suggests that COS and MeSH formation was linked to H 2 S generation and/or post-catagenetic interactions between hydrocarbons and H 2 S, mainly related to thermochemical sulfate reduction (TSR). In contrast, the distribution of higher molecular weight VOSC seems to be controlled by source rock facies, rather than H 2 S concentration. Principal component analysis of the VOSC compositional data identified some subgroups within the gas families mainly associated with TSR. The results presented in this work reveal that VOSC can be an important auxiliary tool in petroleum system studies.

Atlantic Ocean, Santos Basin↗
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↗
USGS2023

Characterization of a complex sand-rich gas hydrate reservoir system in the Indian marine continental margin with downhole log and seismic data

Logging-while-drilling (LWD) and coring data were acquired in Areas A, B, C and E during the National Gas Hydrate Program Expedition 02 (NGHP-02). At Sites NGHP-02-16, −17, −20, −23 and −24 of Area B in the Indian Krishna-Godavari Basin, the gas hydrate-bearing sand-rich reservoirs directly in contact with an underlying water-saturated sediment were revealed near the seismic-inferred bottom simulating reflector (BSR) along a large anticlinal structure. Lithofacies analysis of cores show that the lower gas hydrate-bearing reservoir section at these sites is an interbedded unit with thin fine-sand layers alternating with clay-rich layers. We reanalyzed the LWD data including resistivity, compressional-wave and shear-wave acoustic velocities to assess and compare the spatial variation of sand-hosted gas hydrate and possible related free-gas accumulations. The presence of free gas-bearing sediments in direct contact with gas hydrate-bearing sediments was confirmed at Sites NGHP-02-20 and −24 along the northeastern flank of the anticline. The sand-rich reservoirs associated with the Area B anticlinal feature reveal different pore-filling constituents and variable boundary conditions, including gas hydrate/water contacts and gas hydrate/free gas contacts. We infer that the sedimentary depositional history at Sites NGHP-02-20 and −24, may have resulted in an upward shift of the base of gas hydrate stability zone, that could have led to in situ gas hydrate dissociation and the accumulation of free gas and coexistence interval below the log-inferred gas hydrate-bearing reservoir sections. This study demonstrates that reservoir heterogeneity and fluid migration were major factors affecting the distribution of gas hydrate and free gas in the identified sand-rich reservoirs.

Journal of Marine and Petroleum Geology↗
USGS2024

Comparison of measured versus modeled TOC in the Tuscaloosa marine shale of Southwestern Mississippi, U.S.A.

This study presents a comparison of measured versus modeled total organic carbon (TOC) in the Upper Cretaceous Tuscaloosa marine shale (TMS) of southwestern Mississippi as a case study to evaluate the effects of mineralogy on the TOC estimated from the ΔlogR method. The ΔlogR method is utilized to calculate TOC, which involves baselining sonic transit time and resistivity log curves in a non-source rock section of the formation. In our application, the well log curves were baselined in the upper TMS, which is described as a non-source rock section, and in the lower TMS above the high resistivity zone (HRZ), which is described as having a higher carbonate content. The ΔlogR calculated TOC values from these two baselining approaches show that the lower baseline results in improved agreement between measured TOC and calculated TOC. This improvement is likely to be due to the lower baseline accounting for the increase in resistivity caused by higher carbonate content, in addition to any presence of TOC. The upper baseline, which has a lower carbonate content, does not account for this resistivity increase. Additionally, sample type appears to affect the comparison of measured and ΔlogR calculated TOC. Most of the samples used in this study are legacy cuttings that were not preserved during storage, exposing the high surface area cuttings to increased rates of oxidation, whereas geophysical logs record the rock properties in situ. To account for this oxidation effect, the difference between the medians of the TMS HRZ TOC core and cuttings values was added to each TOC measurement in this study, resulting in a median measured TOC value that is similar to the median of the lower TMS-baselined ΔlogR calculated TOC value. Overall, this study demonstrates that carbonate content and sample type can affect how well measured and ΔlogR-modeled TOC values compare.

Mississippi↗
USGS2025

Terrebonne Basin, Gulf of Mexico gas hydrate resource evaluation and 3-D modeling of basin-scale sedimentation, salt tectonics, and hydrate system evolution since the early Miocene

In assessing methane hydrate as a potential transitional energy source, quantification of in-place volumes of gas is a first step—and yet, global, regional, and even local estimates of gas volumes contained within hydrate are highly variable, including within the extensively-studied Gulf of Mexico (GoM) gas hydrate province. Here, we construct the first 3-D basin and hydrocarbon system model of the Terrebonne Basin (Walker Ridge protraction area, northern GoM) to estimate in-place resources contained as gas within hydrate, as well as to provide the first estimate of in-place resources contained within free gas accumulations in the basin. The resultant model-predicted 3-D distributions (and saturations) of hydrate are consistent with independent seismic interpretation and borehole observations. This study reveals both sedimentation-driven and salt diapir-driven gas hydrate recycling produce elevated hydrate saturations in the basin (“recycling” occurs when relative upward shifts of the gas hydrate stability zone (GHSZ) cause hydrate dissociation, generating buoyant free gas that may reaccumulate as higher-saturation hydrate at the new base of GHSZ). An important finding of this study (particularly given that, globally, the source of methane in marine hydrate systems tends to be poorly understood) is that microbial sources can explain most or all hydrate occurrences in Terrebonne Basin. We calculate that ∼32 × 10 9 m 3 (∼1.1 10 12 ft 3 ) of methane gas is trapped within hydrate accumulations throughout Terrebonne Basin, while nearly 2 × 10 9 m 3 (∼67 × 10 9 ft 3 ) of methane occurs as free gas at high saturations within sandy reservoirs beneath the GHSZ and ∼35 × 10 9 m 3 (∼1.2 × 10 12 ft 3 ) occurs as free gas at low saturations within muddy units beneath the GHSZ. In total, our calibrated 3-D model predicts that nearly 70 × 10 9 m 3 (∼2.5 × 10 12 ft 3 ) of microbial methane is trapped as gas hydrate and free gas in the Terrebonne Basin.

Marine and Petroleum Geology↗
USGS2001

Salt diapirs in the Dead Sea basin and their relationship to Quaternary extensional tectonics

Regional extension of a brittle overburden and underlying salt causes differential loading that is thought to initiate the rise of reactive diapirs below and through regions of thin overburden. We present a modern example of a large salt diapir in the Dead Sea pull-apart basin, the Lisan diapir, which we believe was formed during the Quaternary due to basin transtension and subsidence. Using newly released seismic data that are correlated to several deep wells, we determine the size of the diapir to be 13 x 10 km. its maximum depth 7.2 km. and its roof 125 m below the surface. From seismic stratigraphy, we infer that the diapir started rising during the early to middle Pleistocene as this section of the basin underwater rapid subsidence and significant extension of the overburden. During the middle to late Pleistocene, the diapir pierced through the extensionally thinned overburden, as indicated by rim synclines, which attest to rapid salt withdrawal from the surrounding regions. Slight positive topography above the diapir and shallow folded horizons indicate that it is still rising intermittently. The smaller Sedom diapir, exposed along the western bounding fault of the basin is presently rising and forms a 200 m-high ridge. Its initiation is explained by localized E-W extension due monoclinal draping over the edge of a rapidly subsiding basin during the early to middle Pleistocene, and its continued rise by lateral squeezing due to continued rotation of the Amazyahu diagonal fault.

Marine and Petroleum Geology↗
USGS2002

High-resolution seismic-reflection investigation of the northern Gulf of Mexico gas-hydrate-stability zone

We recorded high-resolution seismic-reflection data in the northern Gulf of Mexico to study gas and gas-hydrate distribution and their relation to seafloor slides. Gas hydrate is widely reported near the seafloor, but is described at only one deep drill site. Our data show high-reflectivity zones (HRZs) near faults, diapirs, and gas vents and interbedded within sedimentary sections at shallow depth (<1 km). The HRZs lie below the gas-hydrate-stability zone (GHSZ) as well as within the zone (less common), and they coincide with zones of shallow water-flows. Bottom simulating reflections are rare in the Gulf, and not documented in our data. We infer HRZs result largely from free gas in sandy beds, with gas hydrate within the GHSZ. Our estimates for the base BHSZ correlate reasonably with the top of HRZs in some thick well-layered basin sections, but poorly where shallow sediments are thin and strongly deformed. The equivocal correlation results from large natural variability of parameters that are used to calculate the base of the GHSZ. The HRZs may, however, be potential indicators of nearby gas hydrate. The HRZs also lie at the base of at least two large seafloor slides (e.g. up to 250 km2) that may be actively moving along decollement faults that sole within the GHSZ or close to the estimated base of the GHSZ. We suspect that water/gas flow along these and other faults such as 'chimney' features provide gas to permit crystallization of gas hydrate in the GHSZ. Such flows weaken sediment that slide down salt-oversteepened slopes when triggered by earthquakes. Published by Elsevier Science Ltd.

Marine and Petroleum Geology↗
USGS2002

The nature of the crust under Cayman Trough from gravity

Considerable crustal thickness variations are inferred along Cayman Trough, a slow-spreading ocean basin in the Caribbean Sea, from modeling of the gravity field. The crust to a distance of 50 km from the spreading center is only 2–3 km thick in agreement with dredge and dive results. Crustal thickness increases to ∼5.5 km at distances between 100 and 430 km west of the spreading center and to 3.5–6 km at distances between 60 and 370 km east of the spreading center. The increase in thickness is interpreted to represent serpentinization of the uppermost mantle lithosphere, rather than a true increase in the volume of accreted ocean crust. Serpentinized peridotite rocks have indeed been dredged from the base of escarpments of oceanic crust rocks in Cayman Trough. Laboratory-measured density and P-wave speed of peridotite with 40–50% serpentine are similar to the observed speed in published refraction results and to the inferred density from the model. Crustal thickness gradually increases to 7–8 km at the far ends of the trough partially in areas where sea floor magnetic anomalies were identified. Basement depth becomes gradually shallower starting 250 km west of the rise and 340 km east of the rise, in contrast to the predicted trend of increasing depth to basement from cooling models of the oceanic lithosphere. The gradual increase in apparent crustal thickness and the shallowing trend of basement depth are interpreted to indicate that the deep distal parts of Cayman Trough are underlain by highly attenuated crust, not by a continuously accreted oceanic crust.

Marine and Petroleum Geology↗