scholarly journals A method for determining gas-hydrate or free-gas saturation of porous media from seismic measurements

Geophysics ◽  
2006 ◽  
Vol 71 (3) ◽  
pp. N21-N32 ◽  
Author(s):  
Matthias Zillmer
Keyword(s):  
Porous Medium ◽  
Bulk Density ◽  
Gas Hydrate ◽  
Pore Space ◽  
Seismic Velocities ◽  
S Wave ◽  
Free Gas ◽  
Gas Saturation ◽  
Wave Velocities ◽  
Standard Deviations

The occurrence of gas hydrate or free gas in a porous medium changes the medium’s elastic properties. Explicit formulas for gas-hydrate or free-gas saturation of pore space on the basis of the Frenkel-Gassmann equations describe the elastic moduli and seismic velocities of a porous medium for low frequencies. A key assumption of the model is that either gas hydrate or free gas is present in the pore space in addition to water. Under this assumption, the method uses measured P- and S-wave velocities and bulk density along with estimates of the moduli and densities of the solid and fluid phases present to determine whether gas or hydrate is present. The method then determines the saturation level of either the gas or the hydrate. I apply the method to published velocity and density data from seismic studies at the antarctic Shetland margin and at the Storegga slide, offshore Norway, and to borehole log and core data from Ocean Drilling Program (ODP) Leg 164 at Blake Ridge, offshore South Carolina. A sensitivity analysis reveals that the standard deviations of the gas-hydrate and free-gas saturations reach 30%–70% of the saturations if the standard deviations of the P- and S-wave velocities and of the bulk density are [Formula: see text] and [Formula: see text], respectively. I conclude that a reliable quantification of gas hydrate and free gas can be achieved by seismic methods only if the seismic velocities and bulk density of the medium are determined with high accuracy from the measured data.

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.

Estimation of gas-hydrate concentration and free-gas saturation at the Norwegian-Svalbard continental margin

2005 ◽  
Vol 53 (6) ◽  
pp. 803-810 ◽  
Author(s):  
José M. Carcione ◽  
Davide Gei ◽  
Giuliana Rossi ◽  
Gianni Madrussani
Keyword(s):  
Continental Margin ◽  
Gas Hydrate ◽  
Free Gas ◽  
Gas Saturation

Factors Affecting the Estimation of Gas Hydrate and Free Gas Saturation

2006 ◽  
Vol 49 (2) ◽  
pp. 441-449 ◽  
Author(s):  
Xiu-Juan WANG ◽  
Shi-Guo WU ◽  
Xue-Wei LIU
Keyword(s):  
Gas Hydrate ◽  
Factors Affecting ◽  
Free Gas ◽  
Gas Saturation

Identification of gas hydrate dissociation from wireline-log data in the Shenhu area, South China Sea

Geophysics ◽  
2012 ◽  
Vol 77 (3) ◽  
pp. B125-B134 ◽  
Author(s):  
Xiujuan Wang ◽  
Myung Lee ◽  
Shiguo Wu ◽  
Shengxiong Yang
Keyword(s):  
Wave Velocity ◽  
Gas Hydrate ◽  
Seismic Data ◽  
Pore Space ◽  
P Wave ◽  
Well Log ◽  
Hydrate Dissociation ◽  
Free Gas ◽  
P Wave Velocity

Wireline logs were acquired in eight wells during China’s first gas hydrate drilling expedition (GMGS-1) in April–June of 2007. Well logs obtained from site SH3 indicated gas hydrate was present in the depth range of 195–206 m below seafloor with a maximum pore-space gas hydrate saturation, calculated from pore water freshening, of about 26%. Assuming gas hydrate is uniformly distributed in the sediments, resistivity calculations using Archie’s equation yielded hydrate-saturation trends similar to those from chloride concentrations. However, the measured compressional (P-wave) velocities decreased sharply at the depth between 194 and 199 mbsf, dropping as low as [Formula: see text], indicating the presence of free gas in the pore space, possibly caused by the dissociation of gas hydrate during drilling. Because surface seismic data acquired prior to drilling were not influenced by the in situ gas hydrate dissociation, surface seismic data could be used to identify the cause of the low P-wave velocity observed in the well log. To determine whether the low well-log P-wave velocity was caused by in situ free gas or by gas hydrate dissociation, synthetic seismograms were generated using the measured well-log P-wave velocity along with velocities calculated assuming both gas hydrate and free gas in the pore space. Comparing the surface seismic data with various synthetic seismograms suggested that low P-wave velocities were likely caused by the dissociation of in situ gas hydrate during drilling.

Estimating seismic velocities at ultrasonic frequencies in partially saturated rocks

Geophysics ◽  
1994 ◽  
Vol 59 (2) ◽  
pp. 252-258 ◽  
Author(s):  
Gary Mavko ◽  
Richard Nolen‐Hoeksema
Keyword(s):  
Large Scale ◽  
Scale Effects ◽  
Pore Space ◽  
Degree Of Saturation ◽  
Velocity Versus ◽  
Seismic Velocities ◽  
Pressure Gradients ◽  
Pore Scale ◽  
S Wave ◽  
Partially Saturated

Seismic velocities in rocks at ultrasonic frequencies depend not only on the degree of saturation but also on the distribution of the fluid phase at various scales within the pore space. Two scales of saturation heterogeneity are important: (1) saturation differences between thin compliant pores and larger stiffer pores, and (2) differences between saturated patches and undersaturated patches at a scale much larger than any pore. We propose a formalism for predicting the range of velocities in partially saturated rocks that avoids assuming idealized pore shapes by using measured dry rock velocity versus pressure and dry rock porosity versus pressure. The pressure dependence contains all of the necessary information about the distribution of pore compliances for estimating effects of saturation at the finest scales where small amounts of fluid in the thinnest, most compliant parts of the pore space stiffen the rock in both compression and shear (increasing both P‐ and S‐wave velocities) in approximately the same way that confining pressure stiffens the rock by closing the compliant pores. Large‐scale saturation patches tend to increase only the high‐frequency bulk modulus by amounts roughly proportional to the saturation. The pore‐scale effects will be most important at laboratory and logging frequencies when pore‐scale pore pressure gradients are unrelaxed. The patchy‐saturation effects can persist even at seismic field frequencies if the patch sizes are sufficiently large and the diffusivities are sufficiently low for the larger‐scale pressure gradients to be unrelaxed.

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.

P-to-S-wave velocity ratio in organic shales

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. MR205-MR222 ◽  
Author(s):  
Sheyore John Omovie ◽  
John P. Castagna
Keyword(s):  
Wave Velocity ◽  
Pore Space ◽  
Velocity Ratio ◽  
Organic Content ◽  
Theoretical Modeling ◽  
S Wave ◽  
Lower Velocity ◽  
Wave Velocities ◽  
Ultrasonic Measurements

In situ P- and S-wave velocity measurements in a variety of organic-rich shales exhibit P-to-S-wave velocity ratios that are significantly lower than lithologically similar fully brine-saturated shales having low organic content. It has been hypothesized that this drop could be explained by the direct influence of kerogen on the rock frame and/or by the presence of free hydrocarbons in the pore space. The correlation of hydrocarbon saturation with total organic content in situ makes it difficult to separate these possible mechanisms using log data alone. Theoretical bounding equations, using pure kerogen as an end-member component without associated gas, indicate that kerogen reduces the P- and S-wave velocities but does not in general reduce their ratio enough to explain the observed low velocity ratio. The theoretical modeling is consistent with ultrasonic measurements on organic shale core samples that indicate no dependence of velocity ratios on the kerogen volume alone. Sonic log measurements of P- and S-wave velocities in seven organic-rich shale formations deviate significantly (typically more than 5%) from the Greenberg-Castagna empirical brine-saturated shale trend toward lower velocity ratios. In these formations, and on core measurements, Gassmann fluid substitution to 100% brine saturation yields velocity ratios consistent with the Greenberg-Castagna velocity trend for fully brine-saturated shales, despite the high organic content. These sonic and ultrasonic measurements, as well as theoretical modeling, suggest that the velocity ratio reduction in organic shales is best explained by the presence of free hydrocarbons.

scholarly journals OBS Data Analysis to Quantify Gas Hydrate and Free Gas in the South Shetland Margin (Antarctica)

Energies ◽  
2018 ◽  
Vol 11 (12) ◽  
pp. 3290 ◽  
Author(s):  
Sha Song ◽  
Umberta Tinivella ◽  
Michela Giustiniani ◽  
Sunny Singhroha ◽  
Stefan Bünz ◽  
...  
Keyword(s):  
Velocity Field ◽  
Wave Velocity ◽  
Gas Hydrate ◽  
P Wave ◽  
Ocean Bottom ◽  
Ocean Bottom Seismometer ◽  
S Wave ◽  
Free Gas ◽  
Hydrate Reservoir ◽  
Gas Hydrate Reservoir

The presence of a gas hydrate reservoir and free gas layer along the South Shetland margin (offshore Antarctic Peninsula) has been well documented in recent years. In order to better characterize gas hydrate reservoirs, with a particular focus on the quantification of gas hydrate and free gas and the petrophysical properties of the subsurface, we performed travel time inversion of ocean-bottom seismometer data in order to obtain detailed P- and S-wave velocity estimates of the sediments. The P-wave velocity field is determined by the inversion of P-wave refractions and reflections, while the S-wave velocity field is obtained from converted-wave reflections received on the horizontal components of ocean-bottom seismometer data. The resulting velocity fields are used to estimate gas hydrate and free gas concentrations using a modified Biot‐Geertsma‐Smit theory. The results show that hydrate concentration ranges from 10% to 15% of total volume and free gas concentration is approximately 0.3% to 0.8% of total volume. The comparison of Poisson’s ratio with previous studies in this area indicates that the gas hydrate reservoir shows no significant regional variations.

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