Interpreting structural controls on hydrate and free-gas accumulation using well and seismic information from the Gulf of Mexico

Geophysics ◽  
2010 ◽  
Vol 75 (1) ◽  
pp. B35-B46 ◽  
Author(s):  
Ashwani Dev ◽  
George A. McMechan
Keyword(s):  
Gulf Of Mexico ◽  
Fault Zone ◽  
Acoustic Impedance ◽  
Fluid Transport ◽  
Pore Space ◽  
Well Logs ◽  
Free Gas ◽  
Bottom Simulating Reflector ◽  
Gas Accumulation ◽  
Hydrate Stability

The effect of the structural setting on gas hydrate and free-gas accumulation near the East Casey fault zone at Keathley Canyon in the Gulf of Mexico is investigated using well logs and 2D and 3D acoustic-impedance inversions. We interpret two zones from the well logs: a probable hydrate zone and a dissociating hydrate zone. We interpret hydrates as fracture fillings in the clay-dominated formation with maximum saturation of approximately 30% of the available pore space, and maximum volumetric concentration of approximately 12%. The maximum free-gas concentration below the interpreted bottom simulating reflector (BSR) is less than 4%. Resistivity measurements alone are incon-clusive; complimentary measurements, such as sonic, reduce hy-drate interpretation ambiguities. Seismic data in 3D and the derived acoustic-impedance volume are interpreted in terms of a BSR, a high [Formula: see text]-impedance hydrate zone, and free gas. We interpret two bright, low [Formula: see text]-impedance features terminating at the BSR as free-gas accumulations. The contrast in average [Formula: see text]-impedance across the fault suggests a change in lithology across the fault zone, and free-gas transport along, and to the west of, the fault. Variations in depths of interpreted free-gas zones suggest either a significant lateral variation in the hydrate stability across the fault zone, or coexistence of hydrates and free gas within the hydrate stability zone, or both. The dynamics of the tectonic environment imply nonequilibrium conditions of time-dependent temperature, pressure, or fluid transport.

Estimation of gas hydrate and free gas saturation, concentration, and distribution from seismic data

Geophysics ◽  
2002 ◽  
Vol 67 (2) ◽  
pp. 582-593 ◽  
Author(s):  
Shaoming Lu ◽  
George A. McMechan
Keyword(s):  
Gas Hydrate ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Single Channel ◽  
Pore Space ◽  
Theoretical Models ◽  
Free Gas ◽  
Bottom Simulating Reflector ◽  
Saturation Concentration ◽  
Empirical Relations

Gas hydrates contain a major untapped source of energy and are of potential economic importance. The theoretical models to estimate gas hydrate saturation from seismic data predict significantly different acoustic/elastic properties of sediments containing gas hydrate; we do not know which to use. Thus, we develop a new approach based on empirical relations. The water‐filled porosity is calibrated (using well‐log data) to acoustic impedance twice: one calibration where gas hydrate is present and the other where free gas is present. The water‐filled porosity is used in a combination of Archie equations (with corresponding parameters for either gas hydrate or free gas) to estimate gas hydrate or free gas saturations. The method is applied to single‐channel seismic data and well logs from Ocean Drilling Program leg 164 from the Blake Ridge area off the east coast of North America. The gas hydrate above the bottom simulating reflector (BSR) is estimated to occupy ∼3–8% of the pore space (∼2–6% by volume). Free gas is interpreted to be present in three main layers beneath the BSR, with average gas saturations of 11–14%, 7–11%, and 1–5% of the pore space (6–8%, 4–6%, and 1–3% by volume), respectively. The estimated saturations of gas hydrate are very similar to those estimated from vertical seismic profile data and generally agree with those from independent, indirect estimates obtained from resistivity and chloride measurements. The estimated free gas saturations agree with measurements from a pressure core sampler. These results suggest that locally derived empirical relations between porosity and acoustic impedance can provide cost‐effective estimates of the saturation, concentration, and distribution of gas hydrate and free gas away from control wells.

Quantitative interpretation for gas hydrate accumulation in the eastern Green Canyon Area, Gulf of Mexico using seismic inversion and rock physics transform

Geophysics ◽  
2011 ◽  
Vol 76 (4) ◽  
pp. B139-B150 ◽  
Author(s):  
Zijian Zhang ◽  
De-hua Han ◽  
Qiuliang Yao
Keyword(s):  
Gulf Of Mexico ◽  
Gas Hydrate ◽  
Pore Space ◽  
Rock Physics ◽  
Seismic Inversion ◽  
Bright Spot ◽  
Quantitative Interpretation ◽  
Free Gas ◽  
Qualitative And Quantitative ◽  
Amplitude Data

Gas hydrate can be interpreted from seismic data through observation of bottom simulating reflector (BSR). It is a challenge to interpret gas hydrate without BSR. Three-dimensional qualitative and quantitative seismic interpretations were used to characterize gas hydrate distribution and concentration in the eastern Green Canyon area of the Gulf of Mexico, where BSR is absent. The combination of qualitative and quantitative interpretation reduces ambiguities in the estimation and identification of gas hydrate. Sandy deposition and faults are qualitatively interpreted from amplitude data. The 3D acoustic impedance volume was interpreted in terms of high P-impedance hydrate zones and low P-impedance free gas zones. Gas hydrate saturation derived from P-impedance is estimated by a rock physics transform. We interpreted gas hydrate in the sand-prone sediments with a maximum saturation of approximately 50% of the pore space. Sheet-like and some bright spot gas hydrate accumulations are interpreted. The interpretation of sheet-like gas hydrate within sand-prone sediments around faults suggests that fluid moves into the sand zones laterally by conduits. Variations in depths of interpreted gas hydrate zones imply nonequilibrium conditions. Low P-impedance free gas zones within high P-impedance gas hydrate zones imply possible coexistence of hydrate and free gas within the hydrate stability zone. We propose that gas hydrate distribution and concentration are associated with structures, buried sedimentary bodies, sources of gas, and fluid flux.

Characterization of elastic properties of near-surface and subsurface deepwater hydrate-bearing sediments

Geophysics ◽  
2013 ◽  
Vol 78 (3) ◽  
pp. D169-D179 ◽  
Author(s):  
Zijian Zhang ◽  
De-hua Han ◽  
Daniel R. McConnell
Keyword(s):  
Wave Velocity ◽  
Elastic Constants ◽  
Gas Hydrate ◽  
Effective Medium Theory ◽  
Pore Space ◽  
Seismic Interpretation ◽  
P Wave ◽  
Near Surface ◽  
Free Gas ◽  
Hydrate Bearing Sediments

Hydrate-bearing sands and shallow nodular hydrate are potential energy resources and geohazards, and they both need to be better understood and identified. Therefore, it is useful to develop methodologies for modeling and simulating elastic constants of these hydrate-bearing sediments. A gas-hydrate rock-physics model based on the effective medium theory was successfully applied to dry rock, water-saturated rock, and hydrate-bearing rock. The model was used to investigate the seismic interpretation capability of hydrate-bearing sediments in the Gulf of Mexico by computing elastic constants, also known as seismic attributes, in terms of seismic interpretation, including the normal incident reflectivity (NI), Poisson’s ratio (PR), P-wave velocity ([Formula: see text]), S-wave velocity ([Formula: see text]), and density. The study of the model was concerned with the formation of gas hydrate, and, therefore, hydrate-bearing sediments were divided into hydrate-bearing sands, hydrate-bearing sands with free gas in the pore space, and shallow nodular hydrate. Although relations of hydrate saturation versus [Formula: see text] and [Formula: see text] are different between structures I and II gas hydrates, highly concentrated hydrate-bearing sands may be interpreted on poststack seismic amplitude sections because of the high NI present. The computations of elastic constant implied that hydrate-bearing sands with free gas could be detected with the crossplot of NI and PR from prestack amplitude analysis, and density may be a good hydrate indicator for shallow nodular hydrate, if it can be accurately estimated by seismic methods.

scholarly journals Thermal State of the Blake Ridge Gas Hydrate Stability Zone (GHSZ)—Insights on Gas Hydrate Dynamics from a New Multi-Phase Numerical Model

Energies ◽  
2019 ◽  
Vol 12 (17) ◽  
pp. 3403 ◽  
Author(s):  
Burwicz ◽  
Rüpke
Keyword(s):  
Numerical Model ◽  
Gas Hydrate ◽  
Methane Flux ◽  
Stability Zone ◽  
Free Gas ◽  
Blake Ridge ◽  
Geochemical Profiles ◽  
Multi Phase ◽  
Hydrate Stability

Marine sediments of the Blake Ridge province exhibit clearly defined geophysical indications for the presence of gas hydrates and a free gas phase. Despite being one of the world’s best-studied gas hydrate provinces and having been drilled during Ocean Drilling Program (ODP) Leg 164, discrepancies between previous model predictions and reported chemical profiles as well as hydrate concentrations result in uncertainty regarding methane sources and a possible co-existence between hydrates and free gas near the base of the gas hydrate stability zone (GHSZ). Here, by using a new multi-phase finite element (FE) numerical model, we investigate different scenarios of gas hydrate formation from both single and mixed methane sources (in-situ biogenic formation and a deep methane flux). Moreover, we explore the evolution of the GHSZ base for the past 10 Myr using reconstructed sedimentation rates and non-steady-state P-T solutions. We conclude that (1) the present-day base of the GHSZ predicted by our model is located at the depth of ~450 mbsf, thereby resolving a previously reported inconsistency between the location of the BSR at ODP Site 997 and the theoretical base of the GHSZ in the Blake Ridge region, (2) a single in-situ methane source results in a good fit between the simulated and measured geochemical profiles including the anaerobic oxidation of methane (AOM) zone, and (3) previously suggested 4 vol.%–7 vol.% gas hydrate concentrations would require a deep methane flux of ~170 mM (corresponds to the mass of methane flux of 1.6 × 10−11 kg s−1 m−2) in addition to methane generated in-situ by organic carbon (POC) degradation at the cost of deteriorating the fit between observed and modelled geochemical profiles.

Outcrops and well logs as a practicum for calibrating the accuracy of traveltime tomograms

2015 ◽  
Vol 3 (3) ◽  
pp. SY27-SY40 ◽  
Author(s):  
Sherif M. Hanafy ◽  
Ann Mattson ◽  
Ronald L. Bruhn ◽  
Shengdong Liu ◽  
Gerard T. Schuster
Keyword(s):  
High Resolution ◽  
Fault Zone ◽  
Great Basin ◽  
Seismic Tomography ◽  
Seismic Data ◽  
Hanging Wall ◽  
Normal Fault ◽  
Well Logs ◽  
Drill Core ◽  
Sufficient Detail

We have developed two case studies demonstrating the use of high-resolution seismic tomography and reflection imaging in the field of paleoseismology. The first study, of the Washington fault in southern Utah, USA, evaluated the subsurface deposits in the hanging wall of the normal fault. The second study, of the Mercur fault in the eastern Great Basin of Utah, USA, helped to establish borehole locations for sampling subsurface colluvial deposits buried deeper than those previously trenched along the fault zone. We evaluated the seismic data interpretations by comparison with data obtained by trenching and logging deposits across the Washington fault, and by drill-core sampling and video logging of boreholes penetrating imaged deposits along the Mercur fault. The seismic tomograms provided critical information on colluvial wedges and faults but lacked sufficient detail to resolve individual paleoearthquakes.

Shale Gas-in-Place Calculations Part I: New Pore-Scale Considerations

SPE Journal ◽  
2011 ◽  
Vol 17 (01) ◽  
pp. 219-229 ◽  
Author(s):  
Ray J. Ambrose ◽  
Robert C. Hartman ◽  
Mery Diaz-Campos ◽  
I. Yucel Akkutlu ◽  
Carl H. Sondergeld
Keyword(s):  
Shale Gas ◽  
Organic Material ◽  
Storage Capacity ◽  
Pore Space ◽  
Ion Beam ◽  
Gas Storage ◽  
Organic Content ◽  
Free Gas ◽  
Adsorbed Phase ◽  
Small Pore

Summary Using focused-ion-beam (FIB)/scanning-electron-microscope (SEM) imaging technology, a series of 2D and 3D submicroscale investigations revealed a finely dispersed porous organic (kerogen) material embedded within an inorganic matrix. The organic material has pores and capillaries having characteristic lengths typically less than 100 nm. A significant portion of total gas in place appears to be associated with interconnected large nanopores within the organic material. Thermodynamics (phase behavior) of fluids in these pores is quite different; gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a different density profile. This raises serious questions related to gas-in-place calculations: Under reservoir conditions, what fraction of the pore volume of the organic material can be considered available as free gas, and what fraction is taken up by the adsorbed phase? How accurately is the shale-gas storage capacity estimated using the conventional volumetric methods? And finally, do average densities exist for the free and the adsorbed phases? We combine the Langmuir adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the pore space taken up by the sorbed phase. The method yields a total-gas-in-place prediction. Molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature predict density profiles across the pores and show that (a) the adsorbed methane forms a 0.38-nm monolayer phase and (b) the adsorbed-phase density is 1.8–2.5 times larger than that of bulk methane. These findings could be a more important consideration with larger hydrocarbons and suggest that a significant adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, calculations show a 10–25% decrease in total gas-storage capacity compared with that using the conventional approach. The role of sorbed gas is more important than previously thought. The new methodology is recommended for estimating shale gas in place.

Fluid dynamics at the base of hydrate-bearing sediments at the Vestnesa Ridge inferred from 5 years of high-resolution 4D seismic surveying

2020 ◽  
Author(s):  
Malin Waage ◽  
Stefan Bünz ◽  
Kate Waghorn ◽  
Sunny Singhorha ◽  
Pavel Serov
Keyword(s):  
High Resolution ◽  
Gas Hydrate ◽  
Seismic Data ◽  
Time Lapse ◽  
Stability Zone ◽  
Seismic Surveys ◽  
Free Gas ◽  
4D Seismic ◽  
Hydrate Bearing Sediments ◽  
Hydrate Stability

<p>The transition from gas hydrate to gas-bearing sediments at the base of the hydrate stability zone (BHSZ) is commonly identified on seismic data as a bottom-simulating reflection (BSR). At this boundary, phase transitions driven by thermal effects, pressure alternations, and gas and water flux exist. Sedimentation, erosion, subsidence, uplift, variations in bottom water temperature or heat flow cause changes in marine gas hydrate stability leading to expansion or reduction of gas hydrate accumulations and associated free gas accumulations. Pressure build-up in gas accumulations trapped beneath the hydrate layer may eventually lead to fracturing of hydrate-bearing sediments that enables advection of fluids into the hydrate layer and potentially seabed seepage. Depletion of gas along zones of weakness creates hydraulic gradients in the free gas zone where gas is forced to migrate along the lower hydrate boundary towards these weakness zones. However, due to lack of “real time” data, the magnitude and timescales of processes at the gas hydrate – gas contact zone remains largely unknown. Here we show results of high resolution 4D seismic surveys at a prominent Arctic gas hydrate accumulation – Vestnesa ridge - capturing dynamics of the gas hydrate and free gas accumulations over 5 years. The 4D time-lapse seismic method has the potential to identify and monitor fluid movement in the subsurface over certain time intervals. Although conventional 4D seismic has a long history of application to monitor fluid changes in petroleum reservoirs, high-resolution seismic data (20-300 Hz) as a tool for 4D fluid monitoring of natural geological processes has been recently identified.<br><br>Our 4D data set consists of four high-resolution P-Cable 3D seismic surveys acquired between 2012 and 2017 in the eastern segment of Vestnesa Ridge. Vestnesa Ridge has an active fluid and gas hydrate system in a contourite drift setting near the Knipovich Ridge offshore W-Svalbard. Large gas flares, ~800 m tall rise from seafloor pockmarks (~700 m diameter) at the ridge axis. Beneath the pockmarks, gas chimneys pierce the hydrate stability zone, and a strong, widespread BSR occurs at depth of 160-180 m bsf. 4D seismic datasets reveal changes in subsurface fluid distribution near the BHSZ on Vestnesa Ridge. In particular, the amplitude along the BSR reflection appears to change across surveys. Disappearance of bright reflections suggest that gas-rich fluids have escaped the free gas zone and possibly migrated into the hydrate stability zone and contributed to a gas hydrate accumulation, or alternatively, migrated laterally along the BSR. Appearance of bright reflection might also indicate lateral migration, ongoing microbial or thermogenic gas supply or be related to other phase transitions. We document that faults, chimneys and lithology constrain these anomalies imposing yet another control on vertical and lateral gas migration and accumulation. These time-lapse differences suggest that (1) we can resolve fluid changes on a year-year timescale in this natural seepage system using high-resolution P-Cable data and (2) that fluids accumulate at, migrate to and migrate from the BHSZ over the same time scale.</p>

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