Gas Hydrate Occurrence Research Articles

High Gas Hydrate and Free Gas Concentrations: An Explanation for Seeps Offshore South Mocha Island

Recent studies have reported cold seeps offshore of Mocha Island. Gas hydrate occurrences along the Chilean margin could explain seeps presence. Gas-phase (gas hydrate and free gas) and geothermal gradients were estimated analysing two seismic sections. Close to Mocha Island (up to 20 km) were detected high (up to 1900 m/s) and low (1260 m/s) velocities associated with high gas hydrate (up to 20% of total volume) and free gas (up to 1.1% of total volume) concentrations, respectively. A variable and high geothermal gradient (65–110 °C/km) was obtained. These results are related to high supply of deep fluids canalised by faults and fractures. Faraway from Mocha Island (>60 km), free gas concentrations decrease to 0.3% of total volume and low geothermal gradient (from 35 to 60 °C/km) are associated with low fluids supply. Finally, we propose gas hydrate dissociation processes as the main supply source for seeps in the vicinity of Mocha Island. These processes can be caused by: (a) active faults and seismic activity; and (b) warm fluid expulsion from deeper zones altering hydrate stability conditions. In both cases, gas hydrate dissociation could generate slope instability and landslides, as occurred in the past in this region and reported in the literature.

New technique for accurate porosity estimation from logging-while-drilling nuclear magnetic resonance data, NGHP-02 expedition, offshore, India

Abstract Drilling and acquiring high-quality downhole log data in the gas hydrate–bearing sedimentary sections, found mostly in deep marine environments and at low temperatures, is often challenging because of the disseminated gas hydrates and mostly unconsolidated nature of the host sediments. Logging while drilling (LWD) technology was used in National Gas Hydrate Program Expedition 02 (NGHP-02) in 25 wellbores to acquire data needed for the comprehensive analysis of gas hydrate occurrences offshore eastern India. The LWD tools deployed included a nuclear magnetic resonance (NMR) tool along with a density measurement tool for porosity computation, a high-resolution resistivity imaging tool for fracture evaluation and depositional system identification, and a borehole acoustic tool for gas hydrate identification and pore-pressure monitoring (by measuring deviation of sonic velocity from normal compaction trend). The NMR LWD tool measures transversely relaxing signal (echoes) decay, which is calibrated and inverted into transverse relaxation times or a T2 distribution (Figure 2). The T2 distribution is then summed to compute NMR porosity. Due to the solid nature of gas hydrates at in situ conditions, they are invisible to NMR. It is fundamental for gas hydrate identification to look for zones with differences between the NMR porosity and density porosity. This paper describes a new evaluation technique that addresses the porosity “deficit problem” due to the fast T2 relaxation observed in NMR data acquired during NGHP-02. In the new algorithm, the T1-T2 distributions are jointly inverted, compared to conventional NMR processing, which inverts a T2 distribution from the echo signal using a constant T1/T2 ratio. It is observed that with the conventional method which assumes a constant T1/T2 ratio, the NMR porosity in gas hydrate bearing zones is underestimated by about 3–6 porosity units, and the derived gas hydrate saturations are overestimated by ∼8–10%.

Numerical simulations of depressurization-induced gas production from an interbedded turbidite gas hydrate-bearing sedimentary section in the offshore India: Site NGHP-02-16 (Area-B)

Abstract The recent National Gas Hydrate Program Expedition 02 (NGHP-02) identified the existence of gas hydrate-bearing sand reservoirs at a number of sites in the offshore of India including Site NGHP-02-16 in Area-B of the Krishna-Godavari Basin. The architecture of that gas hydrate accumulation is characterized by thin, gas hydrate-bearing, high quality sand layers interbedded with mud layers within a turbidite sedimentary interval. The lowest gas hydrate-bearing layer contacting a thinly-interbedded saline aquifer designates the base of the gas hydrate stability zone (BGHSZ). The proximity of the BGHSZ and the average temperature around 20 °C make the reservoir a favorable target for hydrate destabilization by means of the depressurization method. The results of the reservoir simulations indicate high gas production potential from this marine gas hydrate deposit with manageable concomitant water production using a well completion design that hydraulically isolates layers with water-saturated sands. Using a detailed geological input model, the predicted cumulative gas rates reach ∼3.1 × 104 m3/day (∼1.1 MMscf/day) after 90 days of continuous depressurization and demonstrate sustained production rates ∼3.0 × 104 m3/day (∼1.0 MMscf/day) after 5 years of production. The interbedded nature of this gas hydrate occurrence promotes the development of horizontal dissociation interfaces between gas hydrate-bearing sand and mud layers. As a result, non-uniform gas production along the horizontal interfaces becomes a primary determinant of reservoir performance. Simulation cases have been executed to determine the impact of the uncertainty in in situ reservoir permeability and the manner in which intrinsic permeability dynamically changes during dissociation in response to the imposed effective stress increase. The cases based on low initial effective permeability and high sensitivity of compaction to stress result in the least favorable production predictions.

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

Abstract 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.

Maximum tolerance for water content at various stages of a natuna production

Though the Natuna field in offshore Indonesia contains natural gas resources, its CO2 content exceeds 70%. While existing technologies can handle the separation challenges, the question of CO2 transport and storage will still remain due to the lack of aquifer storage sites with sufficient sealing integrity in this part of South Asia. Substantial occurrences of natural gas hydrates have been discovered in offshore Indonesia roughly 700 miles from Natuna, making the pipeline transport economically feasible. This work aimed to assess the risk of hydrate formation during this transport as evaluated by two different approaches: traditional method based on water dew-point versus evaluation accounting for alternative routes of hydrate formation. The hydrate risk analysis was also conducted for produced natural gas at transport conditions. We have investigated the case study involving using the separated CO2 for simultaneous safe long-term storage of CO2 and release of methane for in situ hydrates located at the North Makassar Basin in offshore Indonesia. Utilization of CO2 will require additive gases to increase gas permeability and reduce the blocking of sediments by new CO2-dominated hydrate. This analysis was conducted for variable content of nitrogen and H2S. We have concluded that the water dew-point-based method appears to severely underestimate the risk of hydrate formation; the maximum water concentration it allows in gas will be larger by a factor of eighteen than the one permitted by approaches that used water adsorption on hematite (rust) as the criterion.

Physical property characteristics of gas hydrate-bearing reservoir and associated seal sediments collected during NGHP-02 in the Krishna-Godavari Basin, in the offshore of India

Abstract India's National Gas Hydrate Program Expedition 02 (NGHP-02) was conducted to better understand geologic controls on gas hydrate occurrence and morphology, targeting coarse-grained sediments along the lower continental slope offshore eastern India. This study combines seismic, logging-while-drilling data, and a petroleum system approach to provide a regional geologic and lithologic context for: 1) gas hydrate morphology and distribution, and 2) effects of fine-grained sediments (clays and other grains smaller than 63 μm) on gas production in NGHP-02 Area B in the Krishna-Godavari Basin. Area B seismic data show a buried anticline/syncline structure with strong reflectors, R1 and R2, that delineate two of the five lithologic units: Unit I (shallowest), II (R1), III, IV (R2) and V (below the bas of gas hydrate stability). Throughout Area B, gas hydrate morphology depends on its placement within these units. Specifically, core- and grain-scale measurements indicate fines content exerts a primary control on the gas hydrate distribution and morphology. Units I, II and III are generally fine-grained. On the anticline crest, these units host primarily grain-displacing gas hydrate veins linked to pore-occupying gas hydrate in thin, localized, coarser-grained deposits. Diatoms in Unit III increase porosity with depth, reaching ∼70% where it contacts Unit IV, the gas hydrate reservoir associated with reflector R2. The Unit III lithology and porosity allow fluid and dissolved-phase methane to escape Unit IV and form gas hydrate in the fine-grained overburden. Within Unit IV, fine-grained layers are interbedded with coarser-grained gas hydrate reservoir sands, and the fines content even in the sands is high enough to impact hydraulic and mechanical properties during gas production. Fluid motion during gas production can mobilize fines, which can then clog pore throats, limiting production rates. Pore-water freshening during gas hydrate dissociation can increase fines mobilization, particularly given the smectite identified in the fine-grained interbeds.

Free gas distribution and basal shear zone development in a subaqueous landslide – Insight from 3D seismic imaging of the Tuaheni Landslide Complex, New Zealand

The Hikurangi margin is an active continental margin east of New Zealand's North Island. It is well recognized as a seismically active zone and is known for the occurrence of free gas and gas hydrates within the shallow sediments. A variety of subaqueous landslides can be observed at the margin, including the Tuaheni Landslide Complex off Poverty Bay. This slide complex has been interpreted previously as a slowly creeping landform, as its morphology and internal deformation is comparable to terrestrial earthflows and rock glaciers. In 2014, we acquired a high-resolution 3D seismic volume covering major parts of the Tuaheni South landslide. The 3D data show a variety of fluid migration indicators, free gas accumulations and manifestations of the base of gas hydrate stability in the pre-slide sedimentary units and the lower unit of the landslide system. The data also show that the landslide system is composed of an upper and lower unit that are separated by an intra-debris negative-polarity reflection. Free gas accumulations directly beneath the landslide units suggest that the debris acts as a boundary for rising fluids and only few migration pathways to the intra-debris reflector are observed in the distal parts of the landslide. Deformation within the landslide's debris is focused in the upper landslide unit, and we interpret the intra-debris reflector as a basal shear zone or ‘glide plane’ upon which the debris has been remobilized. The origin of the intra-debris reflector is unclear, but we suggest it could be a relatively coarse-grained horizon that would be prone to fluid flow focusing and the development of excess fluid pressure. Our seismic study provides one of the most detailed examples of a subaqueous landslide system and reveals insights into the fluid flow system and potential basal shear zone development of the Tuaheni Landslide Complex.

Distribution and characteristics of natural gas hydrates in the Shenhu Sea Area, South China Sea

Abstract Structure type, gas composition and cage occupancy are important gas hydrate characteristics which play an important role in calculating gas hydrate stability and estimating the amount of global hydrate-bound methane. China conducted the Fourth gas hydrate drilling campaign (GMGS4) in the Shenhu Sea Area (SSA) of the South China Sea in 2016, during which comprehensive Logging-While-Drilling (LWD) data and natural gas hydrate samples were obtained. The LWD data shows high electrical resistivity and high sound velocity at various depth, indicating the occurrence of gas hydrate in this area. Coexistence of structure I (sI) and structure II (sII) gas hydrates in the South China Sea was confirmed for the first time by using Raman spectra analysis. The methane cage occupancies of large cages and small cages in sI hydrate are 0.95 and 0.96, respectively. The hydration number of sI hydrate is 6.03. Gas composition analysis shows that methane (>98.7%) is the dominate gas, with small amount of heavier hydrocarbon gases (ethane: 0.006%–0.976%, propane: 0.033%–0.216%, isobutane: 0.004%–0.047%) and other non-hydrocarbon gases (carbon dioxide:

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.

Regional stratigraphic framework and gas hydrate occurrence offshore eastern India: Core-log-seismic integration of National Gas Hydrate Program Expedition 02 (NGHP-02) Area-B drill sites

Abstract The Indian National Gas Hydrate Program Expedition 02 (NGHP-02) was designed to study the occurrence of gas hydrate along the passive continental margin of the Indian Peninsula in the Bay of Bengal. Twelve holes were logged and measured with logging-while-drilling (LWD) and five holes were cored in Area-B of NGHP-02. The LWD and coring results in Area-B helped to understand the geological significance of sequence stratigraphy in Krishna-Godavari Basin and identified the occurrence of gas hydrate. This study summarized the log- and litho-units in Area-B and establish three integrated units based on the core-log-seismic integration. Most of the downhole log and core inferred gas hydrate occurrences are in the Late Miocene Integrated-Unit B with several sets of reservoir sections exhibiting favorable conditions for hosting gas hydrate. The gas hydrates reservoirs associated with reflectors R1 and R2 were identified and the R1 reservoirs are characterized by fracture- and pore-filling gas hydrate, and the R2 is in sand-rich sediments with pore-filling gas hydrate at high saturations. The thickness variations associated with the R1 and R2 are possibly associated with the development anticlinal structure and are likely related to syn-sedimentary growth of the folding structures. Major gas hydrate zones exist in and around the R1 and R2 near the BSR depth, and mostly have coincident with the fractures and mass-transport deposits. The spatial distribution of gas hydrate in the R1 and R2 reservoirs is highly influenced by the anticlinal structure. This study can be considered a good case for the future gas hydrate studies and explorations in the nearby areas.

Identifying gas hydrate occurrence state by seismic P-wave attenuation in northern South China Sea

In the process of gas hydrates exploration, the gas hydrate occurrence state is the key factor to determine the exploiting method. In this paper, we find a way to identify gas hydrate occurrence states by seismic P-wave attenuation. We find that the P-wave attenuation characteristics are different between the pore-filling hydrate-bearing sediments and the fracture-filling hydratebearing sediments. The attenuation is prominent in fracture-filling hydrate-bearing sediments. However, the pore-filling hydratebearing sediments have week attenuation effect. We use this difference to identify the gas hydrate occurrences state and apply it in northern South China Sea. The results depict that the P-wave attenuation is an effective attribute to identify gas hydrate occurrence states, which lays a foundation for the identification of gas hydrate occurrence state by seismic P-wave attenuation.

Reservoir volume of gas hydrate stability zones in permafrost regions of China

Gas hydrate is a promising energy resource. Permafrost regions in China are natural gas hydrate prospects. In this study, we summarized the conditions for gas hydrate formation, and analyzed the probable thickness and area of gas hydrate stability zones in the permafrost regions in China. Then the probability of porosity within the gas hydrate stability zones was estimated from lithology, burial history, and compaction curves. Finally, the total reservoir volume for gas hydrate stability zones in permafrost regions was estimated from the joint probability distribution of the effective thickness, area, and porosity. The probable total reservoir volume of the gas hydrate stability zones in the permafrosts in China is in the range of 2.995 × 1012 m3 to 5.081 × 1012 m3, with the best estimate at 4.002 × 1012 m3. The Qinghai-Tibetan Plateau including Qilian (where the occurrence of natural gas hydrate has been proven by coring) has about 55% of the total reservoir volume of the gas hydrate stability zones in China, indicating it has a great resource potential. In the Mohe Basin the reservoir volume of the gas hydrate stability zone ranges from 0.49 × 1012 m3 to 0.79 × 1012 m3, suggesting it is a hopeful future resource exploration area. The best estimate of the total reservoir volume of the gas hydrate stability zones in Northwest China is 1.2 × 1012 m3 which is considerable. However, occurrence of gas hydrate is yet to be confirmed by future exploration. These estimates provide much needed data for further gas hydrate resource exploration and evaluation, as well as environmental protection.

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. • Clay content provides a primary control on the distribution and peak saturation of gas hydrate. • Gas hydrate was not observed to form in the coarse-grained, primary reservoir where the clay fraction exceeded ~0.3. • Overlying fine-grained sediment is a more effective low-permeability seal than the gas hydrate-saturated reservoir is. Imperfect seals in Area C can be linked with incomplete occupation of the coarse-grained sediment by gas hydrate.

Geophysical characterization of a fine-grained gas hydrate reservoir in the Shenhu area, northern South China Sea: Integration of seismic data and downhole logs

Abstract High concentrated gas hydrate deposits in fine-grained sediment are proved to be eligible for exploitation with the current technology. Nevertheless, new insights and more understandings of the accumulation of gas hydrate and characterization of hydrate reservoir in fine-grained sediment are required, which can facilitate the commercial production of gas hydrate in the future. Combining seismic data and downhole logs, here we investigate a fine-grained gas hydrate reservoir in the Shenhu area, northern South China Sea (SCS). Gas hydrate with saturations of 10–45% occurs in fine-grained sediment. Besides the typical bottom-simulating reflectors (BSRs) and high amplitude reflection below BSR, a high amplitude positive reflector (referred to as the top of gas hydrate reservoir reflector; TGHR) exists at the top of high concentrated fine-grained gas hydrate reservoir. According to the result of acoustic impedance inversion, the TGHR is considered to represent a transitional zone from the overlying water-saturated sediment to the underlying high concentrated gas hydrate occurrence zone (GHOZ). Discontinuous BSRs beneath the traditional BSRs are also discovered in the study area, which are interpreted as the seismic evidence of the SII gas hydrate. In the Shenhu area, fluid flow features (such as chimney structures and faults) are found on the ridges where gas hydrate occurs, indicating that gas migration plays a critical role in the formation of gas hydrate in the fine-grained sediment. Our results provide valuable geophysical indications for detecting the presence of gas hydrate in fine-grained sediments.

Submarine slope failures due to pipe structure formation

There is a strong spatial correlation between submarine slope failures and the occurrence of gas hydrates. This has been attributed to the dynamic nature of gas hydrate systems and the potential reduction of slope stability due to bottom water warming or sea level drop. However, 30 years of research into this process found no solid supporting evidence. Here we present new reflection seismic data from the Arctic Ocean and numerical modelling results supporting a different link between hydrates and slope stability. Hydrates reduce sediment permeability and cause build-up of overpressure at the base of the gas hydrate stability zone. Resulting hydro-fracturing forms pipe structures as pathways for overpressured fluids to migrate upward. Where these pipe structures reach shallow permeable beds, this overpressure transfers laterally and destabilises the slope. This process reconciles the spatial correlation of submarine landslides and gas hydrate, and it is independent of environmental change and water depth.

A simplified method for predicting the penetration distance of cementing slurry in gas hydrate reservoirs around wellbore

The permafrost region in the Qinghai-Tibet Plateau of China is abundant in natural gas hydrate (NGH) resources. In this region, there is a great probability of meeting gas hydrate when conducting conventional oil and gas well cementation operations. Because of the relatively developed fractures and not very high pore pressure (usually 3.5–3.6 MPa) in the gas hydrate reservoirs in this area, it is easy for the cementing slurry to penetrate into the gas hydrate reservoirs under the pressure difference during cementing process, undergo hydration and release heat, thus causing hydrate dissociation and cementing quality reduction or even failure. Therefore, it is necessary to first determine the penetration distance of the cementing slurry in the gas hydrate reservoirs to evaluate the effect of hydration of the cementing slurry on the hydrate stability in the reservoirs. In this paper, theoretical and experimental methods for determining the penetration distance value of cementing slurry were established for the first time. The permafrost layer in the Muli area of the Qinghai-Tibet Plateau was selected as the research object and the proposed computational model was verified by using low-density cementing slurry and common cementing process experiments. The results show that the penetration distance calculated by the established computational model is in good agreement with that measured in the experiment, and the computational model can provide technical support for the cementing process design in gas hydrate occurrence area.

Geochemical characteristics of iron in sediments from the Sea of Marmara

Two ~1000 cm long sediment cores were recovered from the Sea of Marmara, one with the occurrence of gas hydrates in the Western High, and the other without hydrates in the Cinarcik Basin. Differences in mineralogical and chemical compositions have been identified between the two sediment cores. Based on the results of the mineralogical and geochemical analyses, the main sources of the sediments are quite similar for both investigated areas, but the authigenic components are different, particularly iron sulfides and carbonates. Authigenic Fe(II) carbonate are much higher in Core MRS-CS-05 in the Western High, while crystalline Fe(III) phases are more abundant in Core MRS-CS-16 in the Cinarcik Basin. Notably, the enrichments of greigite (Fe3S4), a metastable ferromagnetic iron sulfide mineral and intermediate polysulfide, as well as iron carbonates are identified at 400 cmbsf with the maximum iron content in Core MRS-CS-05. These indicate the presence of a more reducing and acidic environment in the Western High, mainly due to higher organic matter content and seepage of heavy hydrocarbons in the sediments.

Comprehensive investigation of submarine slide zones and mass movements at the northern continental slope of South China Sea

Multi-beam bathymetry and seismic sequence surveys in the northern slope of the South China Sea reveal detailed geomorphology and seismic stratigraphy characteristics of canyons, gullies, and mass movements. Modern canyons and gullies are roughly elongated NNW–SSW with U-shaped cross sections at water depths of 400–1000 m. Mass movements include slide complexes, slide scars, and debris/turbidity flows. Slide complexes and slide scars are oriented in the NE–SW direction and cover an area of about 1790 and 926 km2, respectively. The debris/turbidity flows developed along the lower slope. A detailed facies analysis suggests that four seismic facies exist, and the late Cenozoic stratigraphy above the acoustic basement can be roughly subdivided into three sequences separated by regional unconformities in the study area. The occurrence of gas hydrates is marked by seismic velocity anomalies, bottom-simulating reflectors, gas chimneys, and pockmarks in the study area. Seismic observations suggest that modern canyons and mass movements formed around the transition between the last glacial period and the current interglacial period. The possible existence and dissociation of gas hydrates and the regional tectonic setting may trigger instability and mass movements on the seafloor. Canyons may be the final result of gas hydrate dissociation. Our study aims to contribute new information that is applicable to engineering construction required for deep-water petroleum exploration and gas hydrate surveys along any marginal sea.

Sensitivity analysis of P-waves and S-waves to gas hydrate in the Shenhu area using OBS

Compared to towed streamers, ocean-bottom seismometers (OBS) obtain both S-wave data and richer wavefield information. In this paper, the induced polarization method is used to conduct wavefield separation on OBS data obtained from the Shenhu area in the South China Sea. A comparison of the changes in P- and S-waves, and a comprehensive analysis of geological factors within the area, enable analysis and description of the occurrence of natural gas hydrate in the study area. Results show an increase in P-wave velocity when natural gas hydrate exists in the formation, whereas the S-wave velocity remains almost constant, as S-waves can only propagate through the rock skeleton. Therefore, the bottom-simulating reflection (BSR) response of the P-wave is better than that of the S-wave in the frequency analysis profile. In a wide-angle section, the refractive wave of the hydrate layer is evident when using P-wave components but identification is difficult with S-wave components. This velocity model illustrates the sensitivity of P- and S-wave components to gas hydrate. The use of this polarization method and results of analysis provide technical and theoretical support for research on hydrate deposits and other geological features in the Shenhu area.

Relationship between fluid-escape pipes and hydrate distribution in offshore Sabah (NW Borneo)

Fluid-escape pipes represent seismic evidence for the focused cross-stratal migration of fluids. In natural gas hydrate systems, these features serve both as conduits for methane-rich fluids and as preferred locations for the formation of gas hydrates. In this study, 3D seismic, well-log and core data from offshore Sabah (NW Borneo) are used to investigate the controls on the occurrence of fluid-escape pipes and their impact on hydrate distribution in a system dominated by the vertical leakage of thermogenic hydrocarbons.The pipes are observed within a gas hydrate stability zone (GHSZ) that extends 100m below a bottom simulating reflector (BSR), located at 155m below the seafloor (mbsf). Pipes are restricted to an area with evidence of free gas-bearing sediments, suggesting a causative link where the free gas promotes the build-up of critical fluid pressures. The stacking of the upper terminus of fluid-escape pipes at discrete stratigraphic intervals suggests that fluid flow to the seabed has been episodically enhanced. Possible triggers for cyclical increases of pore fluid pressures are sea-level and temperature fluctuations, tectonic activity and gas leakage from deep reservoirs.This fluid flow system further impacts the gas hydrate distribution. The fluid-escape pipes can be locations where hydrates occur at high concentrations up to the seafloor if the pipe is presently active. Therefore, the observed up-bending of the stratigraphic reflections along the pipes are interpreted as a combination of a net volume increase of the host sediment owing to hydrate formation and seismic velocity pull-up effects. Away from the pipes, hydrates do not occur until 65–152mbsf and are present only at low to moderate concentrations. At this site of focused fluid flow, fluid-escape pipes constitute, by volume, only 7–11% of the gas hydrate occurrence zone. Nevertheless, we predict that they could host between 20 and 50% of the whole hydrate volume. It is therefore likely that, in similar systems, a volumetrically significant portion of the total hydrate reservoir is hosted within fluid-escape pipes. The distribution of these features should thus be considered as a critical parameter for hydrate volume estimates.