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USGS2016

Organic petrology and geochemistry of Eocene Suzak bituminous marl, north-central Afghanistan: Depositional environment and source rock potential

Organic geochemistry and petrology of Eocene Suzak bituminous marl outcrop samples from Madr village in north-central Afghanistan were characterized via an integrated analytical approach to evaluate depositional environment and source rock potential. Multiple proxies suggest the organic-rich (TOC ∼6 wt.%) bituminous marls are ‘immature’ for oil generation (e.g., vitrinite R o < 0.4%, T max < 425 °C, PI ≤ 0.05, C 29 ααα S/S + R ≤ 0.12, C 29 ββS/ββS+ααR ≤ 0.10, others), yet oil seeps are present at outcrop and live oil and abundant solid bitumen were observed via optical microscopy. Whole rock sulfur content is ∼2.3 wt.% whereas sulfur content is ∼5.0–5.6 wt.% in whole rock extracts with high polar components, consistent with extraction from S-rich Type IIs organic matter which could generate hydrocarbons at low thermal maturity. Low Fe-sulfide mineral abundance and comparison of Pr/Ph ratios between saturate and whole extracts suggest limited Fe concentration resulted in sulfurization of organic matter during early diagenesis. From these observations, we infer that a Type IIs kerogen in ‘immature’ bituminous marl at Madr could be generating high sulfur viscous oil which is seeping from outcrop. However, oil-seep samples were not collected for correlation studies. Aluminum-normalized trace element concentrations indicate enrichment of redox sensitive trace elements Mo, U and V and suggest anoxic-euxinic conditions during sediment deposition. The bulk of organic matter observed via optical microscopy is strongly fluorescent amorphous bituminite grading to lamalginite, possibly representing microbial mat facies. Short chain n- alkanes peak at C 14 –C 16 ( n- C 17 / n- C 29 > 1) indicating organic input from marine algae and/or bacterial biomass, and sterane/hopane ratios are low (0.12–0.14). Monoaromatic steroids are dominated by C 28 clearly indicating a marine setting. High gammacerane index values (∼0.9) are consistent with anoxia stratification and may indicate intermittent saline-hypersaline conditions. Stable C isotope ratios also suggest a marine depositional scenario for the Suzak samples, consistent with the presence of marine foraminifera including abundant planktic globigerinida (?) and rare benthic discocyclina (?) and nummulites (?). Biomarker 2α-methylhopane for photosynthetic cyanobacteria implies shallow photic zone deposition of Madr marls and 3β-methylhopane indicates presence of methanotrophic archaea in the microbial consortium. The data presented herein are consistent with deposition of Suzak bituminous marls in shallow stratified waters of a restricted marine basin associated with the southeastern incipient or proto-Paratethys. Geochemical proxies from Suzak rock extracts (S content, high polar content, C isotopes, normal (αααR) C 27–29 steranes, and C 29 /C 30 and C 26 /C 25 hopane ratios) are similar to extant data from Paleogene oils produced to the north in the Afghan-Tajik Basin. This observation may indicate laterally equivalent strata are effective source rocks as suggested by previous workers; however, further work is needed to strengthen oil-source correlations.

Marine and Petroleum Geology↗
USGS2024

Mapping the resistivity structure of Walker Ridge 313 in the Gulf of Mexico using the marine CSEM method

A marine controlled source electromagnetic (CSEM) campaign was carried out in the Gulf of Mexico to further develop marine electromagnetic techniques in order to aid the detection and mapping of gas hydrate deposits. Marine CSEM methods are used to obtain an electrical resistivity structure of the subsurface which can indicate the type of substance filling the pore space, such as gas hydrates which are more resistive. Results from the Walker Ridge 313 study (WR 313) are presented in this paper and compared with the Gulf of Mexico Gas Hydrate Joint Industry Project II (JIP2) logging while drilling (LWD) results and available seismic data. The hydrate, known to exist within sheeted sand deposits, is mapped as a resistive region in the two dimensional (2D) CSEM inversion models. This is consistent with the JIP2 LWD resistivity results. CSEM inversions that use seismic horizons provide more realistic results compared to the unconstrained inversions by providing sharp boundaries and architectural control on the location of the resistive and conductive regions in the CSEM model. The seismic horizons include: 1) the base of the gas hydrate stability zone (BGHSZ), 2) the top of salt, and 3) the top and bottom of a fine grained marine mud interval with near vertical hydrate filled fractures, to constrain the CSEM inversion model. The top of salt provides improved location for brines, water saturated salt, and resistive salt. Inversions of the CSEM data map the occurrence of a ‘halo’ of conductive brines above salt. The use of the BGHSZ as a constraint on the inversion helps distinguish between free gas and gas hydrate as well as gas hydrate and water saturated sediments.

Louisiana↗
USGS2019

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

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

Marine and Petroleum Geology↗
USGS2019

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

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

Krishna–Godavari Basin↗
USGS2019

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

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

Marine and Petroleum Geology↗
USGS2019

Multi-measurement approach for establishing the base of gas hydrate occurrence in the Krishna-Godavari Basin for sites cored during Expedition NGHP-02 in the offshore of India

The 2015 National Gas Hydrate Program of India's second expedition, NGHP-02, acquired logging and coring datasets for constraining the base of the gas hydrate occurrence zone (deepest GH) and the theoretical base of gas hydrate stability zone (BGHS). These data are used here for two primary goals: to constrain the deepest occurrence of gas hydrate relative to predicted stability limits and the observed BSR, and to characterize the nature of the contact between gas hydrate-bearing sediment and the underlying gas hydrate-free sediment. A consensus depth for the deepest GH is derived for each NGHP-02 coring site from downhole indicators of gas hydrate occurrence obtained from well-log electrical resistivity and acoustic data, pressure core compressional wave velocity measurements, and conventional core measurements of anomalously low temperatures. To establish the theoretical BGHS, models of gas hydrate phase stability with depth are compared with downhole temperature profiles derived from: 1) assuming a constant geothermal gradient consistent with downhole temperature measurements, and 2) assuming constant heat flow using a geotherm through the downhole temperature measurements and incorporating thermal conductivity calculated from borehole logging data. Although the deepest NGHP-02 GH occurrences are controlled at several sites by a lithologic boundary, most sites have deepest GH occurrences within a single coarse-grained lithology. Cutoffs within a single coarse-grained lithology, which occur for the primary NGHP-02 Area B gas hydrate reservoir, will inhibit pore-pressure drawdowns used to extract methane from gas hydrate as an energy resource.

Bay of Bengal↗
USGS2019

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

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

Marine and Petroleum Geology↗
USGS2019

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

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

Journal of Marine and Petroleum Geology↗
USGS2019

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

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

Marine and Petroleum Geology↗
USGS2019

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

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

Bay of Bengal↗
USGS2019

India National Gas Hydrate Program Expedition 02 summary of scientific results: Evaluation of natural gas hydrate-bearing pressure cores

India’s National Gas Hydrate Program (NGHP) Expedition-02 was conducted in 2015 with the goal of investigating numerous locations that had been determined to be prospective for gas hydrate at high saturation in sand-rich reservoirs. Initial logging while drilling data revealed extensive sand-rich gas hydrate occurrences at multiple drill sites in two broad areas. These sites were further investigated through the acquisition and analyses of pressure cores designed to document 1) gas hydrate occurrence within the reservoirs; 2) the petrophysical nature of the reservoir and associated seals, in their native state as well as during and after the dissociation of gas hydrate; 3) the geomechanical nature of the reservoir and seals; and 4) the geochemical nature of reservoir fluids. The cores were initially evaluated at sea, and select subsamples were transferred for more extensive analyses at specialized laboratories both in Japan and in the United States. The samples encompassed a wide range of gas hydrate saturation (from 0 to 100%) within reservoir sediments ranging from sandy silts to gravels, providing opportunities to extend and refine insights into the nature of gas hydrate reservoirs gained in previous programs. Select findings and implications of this coordinated pressure-core evaluation program are reported in numerous papers within the NGHP-02 Special Thematic Volume and are summarized here with respect to the following issues: the evaluation and mitigation of core disturbance, the assessment of gas hydrate occurrence and saturation, the geomechanics and petrophysics of both reservoirs and “seals” in situ, and the potential dynamic geomechanical and petrophysical behavior of reservoir and seals during production.

Journal of Marine and Petroleum Geology↗
USGS2019

India National Gas Hydrate Program Expedition-02: Operational and technical summary

The India National Gas Hydrate Program is being steered by the government of India's Ministry of Petroleum and Natural Gas (MoPNG) with participation of Directorate General of Hydrocarbons (DGH), Oil and Natural Gas Corporation Limited (ONGC), and the National Oil Companies and Research Institutes of India. The India National Gas Hydrate Program Expedition 01 (NGHP-01) established the presence of gas hydrate in the Krishna Godavari (KG) and Mahanadi Basins and in the offshore area of the Andaman Sea Basin. However, the gas hydrates discovered during NGHP-01 were mainly distributed as fracture-filling material in fine-grained clay-rich sediments. The India National Gas Hydrate Program Expedition 02 (NGHP-02) was carried out with an objective to discover gas hydrate in sand-rich sediment along the eastern offshore margin of India. ONGC planned and executed NGHP-02 on the behalf of the MoPNG. NGHP-02 started on March 3, 2015 and was completed on July 28, 2015 (total 147 days) using the Japanese scientific Drilling Vessel Chikyu (D/V Chikyu). During NGHP-02, 42 holes at 25 sites were drilled, cored, and/or surveyed with downhole logging tools. These sites were located in four areas along the eastern margin of India and formally named Area A (Mahanadi Basin, three sites), Area B (northern part of the KG-Basin, twelve sites), Area C (central part of the KG-Basin, six sites), and Area E (southern part to the KG-Basin, four sites). All 25 sites established during NGHP-02 were first drilled and logged with logging-while-drilling (LWD) tools and an additional 17 holes were then drilled and/or cored with conventional coring tools (HPCS/ESCS) or pressure coring tools (PCTB). Wireline logging was conducted in 10 holes and formation tests using a dual packer Modular Formation Dynamics Tester (MDT) tool were carried out in two holes. The onboard science team used the laboratory facilities on the D/V Chikyu to examine and analyse the physical properties, geochemistry, and sedimentology of all the cores collected during the expedition. Core samples were also analysed in additional post-expedition shore-based studies conducted in numerous domestic and international gas hydrate research laboratories. The NGHP-02 sediment cores were archived at the National Gas Hydrate Core Repository in Mumbai (India), which is associated with the ONGC Gas Hydrate Research and Technology Centre (GHRTC). The necessary data for characterizing the occurrence of gas hydrate, such as interstitial water chlorinities, core-derived gas chemistry, physical and sedimentological properties, thermal images of the recovered cores, pressure core and downhole measured logging data (LWD and/or conventional wireline log data), were obtained from most of the drill sites established during NGHP-02. Almost all the drill sites yielded evidence for the occurrence of gas hydrate; however, the inferred in situ concentration of gas hydrate varied substantially from site to site. For the most part, the interpretation of downhole logging data, core thermal images, interstitial water analyses, and pressure core images from the sites established during NGHP-02 indicate that the occurrence of concentrated gas hydrate is mostly associated with coarser grained (sand-rich) sediments. This paper presents the operational and technical summary of NGHP-02. NGHP-02 started on March 3, 2015 and was completed on July 28, 2015 (total 147 days) using the Japanese scientific Drilling Vessel Chikyu (D/V Chikyu). During NGHP-02, 42 holes at 25 sites were drilled, cored, and/or surveyed with downhole logging tools. These sites were located in four areas along the eastern margin of India and formally named Area A (Mahanadi Basin, three sites), Area B (northern part of the KG-Basin, twelve sites), Area C (central part of the KG-Basin, six sites), and Area E (southern part to the KG-Basin, four sites). All 25 sites established during NGHP-02 were first drilled and logged with logging-while-drilling (LWD) to

Journal of Marine and Petroleum Geology↗
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↗