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We develop an original algorithm for velocity estimation that incorporates the constraints of three seismic functionals: surface wave dispersion, P-receiver function, and S-waveform. Here, we use a parallelized reflectivity algorithm to generate synthetic seismograms and match the observed functionals by a global optimization scheme called very fast simulated annealing (VFSA). This method also allows us to assess the uniqueness and parameter independence of the resultant models. Synthetic tests using surface wave (SW) dispersion and receiver functions (RF), and then SW, RF, and waveforms windowed around the S arrival, establish that inclusion of the third functional results in the best recovery of the model. We employ the algorithm to model the Kachchh basin in Gujarat, India, because the area is of active interest for monitoring purposes, and prior results of RF and SW modeling are available for comparison. The waveform functionals used here are generated from broadband seismograms of teleseismic, deep (396–609 km), and moderate- to large-magnitude (6–6.8) earthquake events recorded at semipermanent seismograph stations in the Kachchh basin. Joint inversion of SW, RF, and S-waveform improves the velocity structure by revealing layers that were not identified in previous modeling that used SW and RF alone. Our model clearly shows low-velocity zones (LVZs), crustal and lithospheric thinning, and the lithosphere–asthenosphere boundary. We estimate the crustal thickness to be 41 km at all but one station, and the lithosphere to be in the range of 70–80 km. P- and S-velocities from the uppermost crust to the Moho vary from 4.7 to 7.0 km/s, and 2.7–4.1 km/s, respectively. [ABSTRACT FROM AUTHOR]

The exploration block MB_OSN-2004/1 in the Gulf of Cambay on the western coast of India is an area of interest for oil and gas exploration, as it is surrounded by hydrocarbon-producing fields including a giant field—Bombay High. However, preliminary studies indicate the presence of non-commercial hydrocarbons (mainly gas) in only three wells among the nine wells drilled in the block. We, therefore, propose an approach to reinvestigate the area by integrating rock physics modeling with multi-attribute linear regression transform to predict hydrocarbon potential from the seismic and well log data. The area of interest (~ 200 km2) is carved out of the main full 3D survey area (~ 1441 km2). We first estimated the saturation of gas with depth from the observed sonic velocity by applying rock physics modeling. Then, we applied a model-based inversion algorithm to compute the acoustic impedance volume by inverting the 3D post-stack seismic data. The computed saturation at well locations and 3D acoustic impedance were used in stepwise multi-attribute linear regression to estimate 3D saturation. The estimated gas saturation was in the range of 5–80% of the pore space within the Paleocene, Eocene, and Oligocene sequences in the Tapti, Mahuva, Pipavav, Panna, and Deccan Trap formations of the study area, where porosity varies in the range of 10–40%. This study suggests that gas can be exploited commercially from wells that penetrate sequences with good reservoir quality as so interpreted. [ABSTRACT FROM AUTHOR]

A complete pore characteristic of the Indian Gondwana shale is studied by combining laboratory experiments and numerical modeling. Mercury injection capillary pressure (MICP), nitrogen gas adsorption (N2GA) and scanning electron microscopy (SEM) are the primary laboratory methods used to evaluate the pore characteristics. The N2GA and MICP were coupled to estimate the pore size distribution (PSD) of Indian Gondwana shale for the first time. The estimated PSD of Gondwana shale varies between 0.5 nm to 100 µm and most of the pores of the samples fall in the micropore and mesopore category. The porosity of Gondwana shale, measured using MICP, varies from 1.13 to 8.01%. The SEM micrographs and hysteresis pattern of isotherms reveal the presence of cylindrical, ink-bottle and slit shape pores in the samples. The BET (Brunauer-Emmett-Teller) surface area of pore for Gondwana shale varies from 3.42 m2/g to 21.5 m2/g. The FHH (Frenkel-Halsey-Hill) fractal model suggests that the Gondwana shale exhibits two types of fractal dimensions with highly complex pore geometry. The adsorption capacity of Gondwana shale is affected by the clay content. This paper attempted a different interpretation approach using experimental data and concluded that Indian Gondwana shale has high gas storage capacity. [ABSTRACT FROM AUTHOR]

Analysis of cores from the Lower Gondwana basin in eastern India confirms the presence of abundant organic matter, indicating a high shale gas prospective zone. Shale is intrinsically (transversely) anisotropic due to the preferential orientation of anisotropic clay platelets depending on the geological processes of deposition. Such anisotropy needs to be incorporated in modeling for an accurate explanation of observed seismic anisotropy in shale. Combined anisotropic formulations of self-consistent approximation (SCA) and differential effective medium (DEM) theory is the most suitable among existing theories to deal with the complex microstructure of shale. We start by predicting the bulk and rigidity moduli of clay mineral aggregates as 21 GPa and 10 GPa from our model, which are difficult to measure in the laboratory due to the small crystal size of clay. A concept of host medium (HM) is presented here, which is constituted of clay mineral aggregates, kerogen, and unconnected pores. Other minerals are added in the biconnected composite constituted of HM and connected pores filled with water. An orientation distribution function (ODF) of clay particles is determined using the combined SCA-DEM theory from the observed ultrasonic velocity measurements. Our model shows strong intrinsic anisotropy at the shallow depth that decreases with depth because of the changes in the microstructure of the shale. The P-velocity predicted from our model, widely used Biot–Gassmann theory (BGT) and Biot–Gassmann theory modified by Lee (BGTL) match well with the measured data where P-wave anisotropy is insignificant. We also predict from our model the volume of kerogen and total organic carbon as 26–43% and 6–8%, respectively. [ABSTRACT FROM AUTHOR]

Causes and effects of global warming have been highly debated in recent years. Nonetheless, injection and storage of CO (CO sequestration) in the subsurface is becoming increasingly accepted as a viable tool to reduce the amount of CO from the atmosphere, which is a primary contributor to global warming. Monitoring of CO movement with time is essential to ascertain that sequestration is not hazardous. A method is proposed here to appraise CO saturation from seismic attributes using differential effective medium theory modified for pressure (PDEM). The PDEM theory accounts pressure-induced fluid flow between cavities, which is a very important investigation in the CO-sequestered regime of heterogeneous microstructure. The study area is the lower Tuscaloosa formation at Cranfield in Mississippi, USA, which is one of the active enhanced oil recovery (EOR), and CO capture and storage (CCS) fields. Injection well (F1) and two observation wells (F2 and F3) are present close (within 112 m) to the detailed area of study for this region. Since the three wells are closely situated, two wells, namely injection well F1 and the furthest observation well F3, have been focused on to monitor CO movement. Time-lapse (pre- and post-injection) log, core and surface seismic data are used in the quantitative assessment of CO saturation from the PDEM theory. It has been found that after approximately 9 months of injection, average CO saturations in F1 and F3 are estimated as 50% in a zone of thickness ~ 25 m at a depth of ~ 3 km. [ABSTRACT FROM AUTHOR]

Estimating the amount of gas-hydrate and free-gas is difficult in deep seas even with scientific coring and downhole measurements. Well data may be incompatible between holes of a site as well as with depth in the same hole. In this paper, we demonstrate an approach to estimate saturation of gas-hydrate from seismic velocities at any site where data set is limited. The study is carried out in the outer Blake Ridge, which is one of the most intensively studied regions of natural gas-hydrate occurrences and a very distinctive example of studying geophysical signatures of gas-hydrate and free-gas in deep marine sediments. Although, downhole measurements from both vertical seismic profiles (VSPs) and sonic logs provide the most accurate and direct measurements of velocity, only VSP velocities at Ocean Drilling Program (ODP) Sites 994, 995, and 997 on the Blake Ridge are used to estimate the saturation of gas-hydrate and free-gas as sonic logs at ODP sites are not reliable. Here we derive a general trend of the background velocity with depth using the porosity and mineralogy from coring at discrete depth intervals. Saturations of gas-hydrate and free-gas are then estimated from this background velocity using the effective medium modeling. The porosity and mineralogical compositions are taken from four different depths at Site 995, as data quality is the best in this hole. Average saturations of gas-hydrate and free-gas at three holes are estimated as 10-14 and 2-3%, respectively. [ABSTRACT FROM AUTHOR]

We investigate the estimation of gas hydrate and free gas concentration using various rock physics models in the Cascadia accretionary prism, which is one of the most intensively studied regions of natural gas hydrate occurrences. Surface seismic reflection data is the most useful and cost-effective in deriving seismic velocity, and hence estimating gas hydrate and free gas across a BSR with depth, if a proper background (without gas hydrate and free gas) velocity is chosen. We have used effective medium theory of Helgerud et al. (EMTH) and, a combination of self-consistent approximation and differential effective medium (SCA-DEM) theory coupled with smoothing approximation for crystalline aggregate. Using the SCA-DEM (non-load-bearing) and EMTH (load-bearing) modeling, we calculate the average saturations of gas hydrate as 17 and 19%, respectively within ~100 m thick sedimentary column using velocity, derived from the surface seismic data. The saturations of gas hydrate are estimated as 15 and 18% using the SCA-DEM, and 20 and 25% using EMTH from the logging-while-drilling and wire-line sonic velocities, respectively. Estimations of gas hydrate from Poisson's ratio are in average 50% for EMTH and 10% for SCA-DEM theory. We obtain the maximum saturation of free gas as 1-2% by employing the SCA-DEM theory either to seismic or sonic velocities, whereas the free-gas saturation varies between 0.1 and 0.4% for EMTH model. The gas hydrate saturation estimated from the sonic velocity and the free gas saturation derived from both the seismic and sonic velocities using the SCA-DEM modeling match quite well with those determined from the pressure core data in the study region. [ABSTRACT FROM AUTHOR]

Due to an unfortunate oversight, the statement in Sect. 6. [ABSTRACT FROM AUTHOR]