Geology Reports⌕ Search
Home/Archive/USGS

USGS · 70196133

National Gas Hydrate Program Expedition 01 offshore India; gas hydrate systems as revealed by hydrocarbon gas geochemistry

Thomas Lorenson·Timothy S. Collett
View original source ↗Export metadata ↓

Abstract

The National Gas Hydrate Program Expedition 01 (NGHP-01) targeted gas hydrate accumulations offshore of the Indian Peninsula and along the Andaman convergent margin. The primary objectives of coring were to understand the geologic and geochemical controls on the accumulation of methane hydrate and their linkages to underlying petroleum systems. Four areas were investigated: 1) the Kerala-Konkan Basin in the eastern Arabian Sea, 2) the Mahanadi and 3) Krishna-Godavari Basins in the western Bay of Bengal, and 4) the Andaman forearc Basin in the Andaman Sea. Upward flux of methane at three of the four of the sites cored during NGHP-01 is apparent from the presence of seafloor mounds, seismic evidence for upward gas migration, shallow sub-seafloor geochemical evidence of methane oxidation, and near-seafloor gas composition that resembles gas from depth. The Kerala-Konkan Basin well contained only CO 2 with no detectable hydrocarbons suggesting there is no gas hydrate system here. Gas and gas hydrate from the Krishna-Godavari Basin is mainly microbial methane with δ 13 C values ranging from −58.9 to −78.9‰, with small contributions from microbial ethane (−52.1‰) and CO 2 . Gas from the Mahanadi Basin was mainly methane with lower concentrations of C 2 -C 5 hydrocarbons (C 1 /C 2 ratios typically >1000) and CO 2 . Carbon isotopic compositions that ranged from −70.7 to −86.6‰ for methane and −62.9 to −63.7‰ for ethane are consistent with a microbial gas source; however deeper cores contained higher molecular weight hydrocarbon gases suggesting a small contribution from a thermogenic gas source. Gas composition in the Andaman Basin was mainly methane with lower concentrations of ethane to isopentane and CO 2, C 1 /C 2 ratios were mainly >1000 although deeper samples were <1000. Carbon isotopic compositions range from −65.2 to −80.7‰ for methane, −53.1 to −55.2‰ for ethane is consistent with mainly microbial gas sources, although one value recorded of −35.4‰ for propane suggests a thermogenic source. Gas hydrate accumulations in the Krishna-Godavari and Mahanadi Basins are the result of a microbially sourced gas hydrate system. The system is enhanced by the migration of microbial gas from surrounding areas through pathways including high-porosity delta sands, shale diapirism, faulting and folding of sediment due to the local processes associated with rapid sediment deposition, sediment overpressure, and the recycling of methane from a rapidly upward moving gas hydrate stability zone. The gas hydrate system in the Andaman Basin is less well constrained due to lack of exploration and occurs in a forearc basin. Each of these hydrate-bearing systems overlies and is likely supported by the presence and possible migration of gas from deeper gas-prone petroleum systems currently generating thermogenic hydrocarbons at much greater depths.

Explore related subjects

Marine and Petroleum GeologyArticle

Keep this discovery

Explore connections, maps & timelines

BibTeXRIS

Thomas Lorenson, Timothy S. Collett. 2018. National Gas Hydrate Program Expedition 01 offshore India; gas hydrate systems as revealed by hydrocarbon gas geochemistry. https://doi.org/10.1016/j.marpetgeo.2017.11.011

Cite the original work for its findings. Save a collection to share your selection of sources.

KEEP EXPLORING

Related USGS reports

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↗
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↗
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↗