Surface Seismic Data Research Articles

Correlation of core and downhole seismic velocities in high-pressure metamorphic rocks: a case study for the COSC-1 borehole, Sweden

Abstract. Deeply rooted thrust zones are key features of tectonic processes and the evolution of mountain belts. Exhumed and deeply eroded orogens like the Scandinavian Caledonides allow us to study such systems from the surface. Previous seismic investigations of the Seve Nappe Complex have shown indications of a strong but discontinuous reflectivity of this thrust zone, which is only poorly understood. The correlation of seismic properties measured on borehole cores with surface seismic data can constrain the origin of this reflectivity. To this end, we compare seismic velocities measured on cores to in situ velocities measured in the borehole. For some intervals of the COSC-1 borehole, the core and downhole velocities deviate by up to 2 km s−1. These differences in the core and downhole velocities are most likely the result of microcracks mainly due to depressurization. However, the core and downhole velocities of the intervals with mafic rocks are generally in close agreement. Seismic anisotropy measured in laboratory samples increases from about 5 % to 26 % at depth, correlating with a transition from gneissic to schistose foliation. Thus, metamorphic foliation has a clear expression in seismic anisotropy. These results will aid in the evaluation of core-derived seismic properties of high-grade metamorphic rocks at the COSC-1 borehole and elsewhere.

Fracture Modeling and Productivity Prediction Technology of Shale Reservoir Based on Multivariate Data

The practice of fracture network fracturing in shale gas layers indicates that the formation of complex fracture networks is directly related to the probability of obtaining a sufficiently large reservoir to effectively rebuild the volume and the ability to obtain high economic benefits. With the continuous deepening of shale gas exploration and development, it is found that the current artificial fractures have slopes, branches and asymmetric distribution. As a result, the production difference between different horizontal wells in the same platform and different fracturing sections of the same horizontal well is obvious. How to optimize the exploration and development plan and promote the economical and effective development of shale gas resources is the most important problem currently facing. The post-evaluation technology of reservoir reconstruction effect has become a key technology. Therefore, it is of great production significance to carry out post-evaluation work by integrating multivariate data. This article takes the SiChuan WeiYuan Shale Gas Demonstration Area as an example, and uses microseismic results and surface seismic data, geology, logging, fracturing and production dynamics data to carry out fracturing fracture modeling and productivity prediction. Provided guidance for fracturing design optimization, development well location, well spacing deployment, and development effectiveness, with good application results.

Analysis technology and application of natural fractures based on microseismic monitoring results

In general, the matrix permeability of shale reservoirs is small, and a developed natural fracture network is required to obtain a good mining effect. Therefore, analyzing and understanding the development of natural fractures in the reservoir plays an important role in increasing the production capacity of shale gas. Microseismic monitoring is the key technology of fracture imaging during hydraulic fracturing. Based on the results of ground microseismic monitoring, this paper analyzed both the waveform and energy of microseismic event, as well as the spatial distribution law, and also combined it with the surface seismic attribution data, formed a natural fracture analysis technology based on the results of microseismic monitoring, which played an important supporting role in real-time optimization and guidance of hydraulic sand fracturing.

Seismic P Wave Velocity Model From 3‐D Surface and Borehole Seismic Data at the Alpine Fault DFDP‐2 Drill Site (Whataroa, New Zealand)

AbstractThe New Zealand Alpine Fault is a major plate boundary that is expected to be close to rupture, allowing a unique study of fault properties prior to a future earthquake. Here we present 3‐D seismic data from the DFDP‐2 drill site in Whataroa to constrain valley structures that were obscured in previous 2‐D seismic data. The new data consist of a 3‐D extended vertical seismic profiling (VSP) survey using three‐component and fiber optic receivers in the DFDP‐2B borehole and a variety of receivers deployed at the surface. The data set enables us to derive a detailed 3‐D P wave velocity model by first‐arrival traveltime tomography. We identify a 100–460 m thick sediment layer (mean velocity 2,200 ± 400 m/s) above the basement (mean velocity 4,200 ± 500 m/s). Particularly on the western valley side, a region of high velocities rises steeply to the surface and mimics the topography. We interpret this to be the infilled flank of the glacial valley that has been eroded into the basement. In general, the 3‐D structures revealed by the velocity model on the hanging wall of the Alpine Fault correlate well with the surface topography and borehole findings. As a reliable velocity model is not only valuable in itself but also crucial for static corrections and migration algorithms, the Whataroa Valley P wave velocity model we have derived will be of great importance for ongoing seismic imaging. Our results highlight the importance of 3‐D seismic data for investigating glacial valley structures in general and the Alpine Fault and adjacent structures in particular.

Off-the-grid vertical seismic profile data regularization by a compressive sensing method

Different from the surface survey, the vertical seismic profile (VSP) survey deploys sources on the surface and geophones in a well. VSP provides higher resolution information of subsurface structures. The faults that cannot be imaged with surface seismic data may be detected with VSP data, and detailed analysis of fracture zones can be achieved with multicomponent VSP. However, one of the main problems is that the sources seldom are acquired on a regular grid in realistic VSP surveys. The irregular samplings cause serious artifacts in migration or imaging, such that data regularization must be implemented first. We have developed a compressive sensing (CS)-based method to regularize nonstationary VSP data. Our method directly operates on irregularly gridded data sets, which is a key contribution compared to the existing CS-based reconstruction methods that work on regular grids. The CS framework consists of a sparsity constraint and a penalty term. We have used the curvelet transform for sparsity constraint of nonstationary events in the regularization term and the nonequispaced Fourier transform to regularize the VSP data in a penalty term. An alternative directional method of multipliers is used for solving the optimization problem. Our method is tested on synthetic, field 2D and 3D VSP data sets. Our method obtains improved reconstructions on continuities of the events and produces fewer artifacts compared to the well-known antileaking Fourier transform method.

From surface seismic data to reservoir elastic parameters using a full-wavefield redatuming approach

SUMMARY Traditionally, reservoir elastic parameters inversion suffers from the overburden multiple scattering and transmission imprint in the local input data used for the target-oriented inversion. In this paper, we present a full-wavefield approach, called reservoir-oriented joint migration inversion (JMI-res), to estimate the high-resolution reservoir elastic parameters from surface seismic data. As a first step in JMI-res, we reconstruct the fully redatumed data (local impulse responses) at a suitable depth above the reservoir from the surface seismic data, while correctly accounting for the overburden interal multiples and transmission losses. Next, we apply a localized elastic full waveform inversion on the estimated impulse responses to get the elastic parameters. We show that JMI-res thus provides much more reliable local target impulse responses, thus yielding high-resolution elastic parameters, compared to a standard redatuming procedure based on time reversal of data. Moreover, by using this kind of approach we avoid the need to apply a full elastic full waveform inversion-type process for the whole subsurface, as within JMI-res elastic full waveform inversion is only restricted to the reservoir target domain.

Subsurface seismic imaging using drill bit noise

SummaryAcoustic signal generated by drill bit cutting action in the borehole can be recorded passively by geophones on the surface and used to produce an image of the subsurface under the geophone array. A single pilot trace is commonly recorded on the drill string and used to convert geophone recordings to equivalent reverse vertical seismic profile data. If there is no pilot measurements on the drill string, seismic interferometry can be used to move continuous sources of energy from the bottom of the borehole to the surface and use conventional seismic methods to image the subsurface.In this study, we recorded the noise coming from drilling operation for several shallow wells over the surface of a small iron ore prospect in Pilbara region of Western Australia. As pilot measurements were not available, we used seismic interferometry to produce virtual shots on the surface. We then migrated virtual data generated along one receiver line for one deep well and four shallower wells over the line. We saw that only deep well with longer drilling time can produce a seismic image with coherent events that are comparable to 3D surface seismic data.

Imaging improvements from subsalt 3D VSP acquisitions in the Gulf of Mexico

From 2015 through 2018, BP acquired six large-scale 3D vertical seismic profile (VSP) data sets at their Gulf of Mexico assets, two at each of the Thunder Horse, Mad Dog, and Atlantis fields. The acquisition of these large-scale data sets was enabled by the development of a 100-level wireline tool and the adoption of simultaneous shooting. With those two developments, it became feasible to acquire data sets with the coverage and data density needed to build high-quality images of the subsurface using 3D VSP acquisitions. There have been recent advances in finite difference modeling to guide the survey design and the high-quality processing that is required to create the 3D VSP image volumes. These volumes have two main advantages over conventional surface seismic data. First, in 3D VSP acquisition, the receiver can be located below the overlying salt bodies, which allows for illumination of the reservoirs that cannot be achieved using surface seismic data. Second, the location of the receivers closer to the imaging targets enables higher frequency content of the resulting VSP data compared to conventional surface seismic images. Both imaging enhancements can have a significant business value, and the resulting VSP data sets have demonstrated a clear impact on business decisions. In the three case studies, we demonstrate the business impact of the 3D VSP data acquired through improvement of imaging of stratigraphic edges, improved interpretation of fault geometry and orientation, and related improvement of the quality of well planning and targeting. We conclude with discussion on cost, global impact, and present recommendations and lessons learned for future surveys.

The value of VSP data through early phases of field appraisal and development: A modeling and acquisition case study in the Gulf of Mexico

The Gulf of Mexico is a rich hydrocarbon province that contains a diversity of petroleum systems play types. Often, identifying drilling targets can be challenging when solely using surface seismic data, particularly in areas with complex salt structures in the overburden. In this paper, we present a vertical seismic profile (VSP) modeling and acquisition case study for an oil field located in a subsalt, deepwater, ultrahigh-pressure high-temperature environment. Our objective was to model the subsurface to guide the acquisition of VSP data during the early phases of exploration and appraisal drilling. In the first exploration well, a salt-proximity VSP designed in a walkaway configuration was carried out to help better define the geometry of a salt overhang and verify anisotropy parameters, helping to reduce a critical uncertainty for imaging the subsalt structure across a large segment within our field area. In the first appraisal well, a zero-offset VSP was collected to establish a direct well tie and further calibrate our velocity model. In the second appraisal well, we utilized walkaway VSP data to form a high-frequency stratigraphic image between the two appraisal wellbores. These data were used to generate an enhanced image of the reservoir section that revealed subtle stratigraphic boundaries, another key subsurface uncertainty. Finally, we modeled both ambitious and conservative 3D VSP acquisition designs to understand the imaging area achieved through a 3D acquisition and undertook an assessment to understand the impact of PP and PS imaging for reservoir characterization. We conclude that VSP data are valuable tools in the early phases of field appraisal and development, and we demonstrate the business value of VSPs to optimize development drilling locations in our study area.

Focal-time analysis: A new method for stratigraphic depth control of microseismicity and induced seismic events

Focal-time analysis is a straightforward data-driven method to obtain robust stratigraphic depth control for microseismicity or induced seismic events. The method eliminates the necessity to build an explicit, calibrated velocity model for hypocenter depth estimation, although it requires multicomponent 3D seismic data that are colocated with surface or near-surface microseismic observations. Event focal depths are initially expressed in terms of zero-offset focal time (two-way P-P reflection time) to facilitate registration and visualization with 3D seismic data. Application of the focal-time method requires (1) high-quality P- and S-wave time picks, which are extrapolated to zero offset and (2) registration of correlative P-P and P-S reflections to provide [Formula: see text] and [Formula: see text] time-depth control. We determine the utility of this method by applying it to a microseismic and induced-seismicity data set recorded with a shallow-borehole monitoring array in Alberta, Canada, combined with high-quality multicomponent surface seismic data. The calculated depth distribution of events is in good agreement with hypocenter locations obtained independently using a nonlinear global-search method. Our results reveal that individual event clusters have distinct depth distributions that can provide important clues about the mechanisms of fault activation.

Mirror reverse time migration using vertical cable seismic data for methane hydrate exploration

Gas hydrates are located in the permafrost and in deepwater shallow sediments, where low temperature and high pressure satisfy the stability conditions of methane clathrates to remain as solid compounds. Hydrates are found in a form of fine-layered or altered-layered structure with hiatuses and necessitate high-resolution surveys, which may not be achieved by conventional marine acquisition using towed streamers. We have developed a recent case study in which the vertical cable seismic (VCS) method has been used for high-resolution subseafloor imaging using a set of buoyed vertical-arrayed receivers that are anchored to the seafloor. The observation close to the target in the deepwater environment provides a higher signal-to-noise ratio and higher resolution. The primary reflections, however, could not achieve reliable depth images in the data processing due to their limited subsurface coverage. We used a reverse time migration (RTM) implementation of mirror imaging to extend the spatial subsurface coverage by using receiver ghost reflections. Because conventional velocity analysis methods are not applicable to the VCS survey due to the asymmetrical reflection path between the source and receiver, we implemented seismic interferometry and generated virtual surface seismic data from VCS data for velocity analysis. To preserve the resolution, amplitudes, and phase characteristics, we applied mirror RTM on the ghost reflections in the original VCS data rather than imaging the virtual data. The introduced case study using a VCS survey for identifying the methane hydrate system of the Umitaka Spur in the Sea of Japan led to high-resolution images, which suggest that a large gas chimney exists beneath a pockmark and is responsible for transferring methane gas from a deep hydrocarbon source to the shallow sediments. A bottom-simulating reflector as the base of the gas hydrate stability zone was also imaged.

A field experiment of walkaway distributed acoustic sensing vertical seismic profile in a deep and deviated onshore well in Japan using a fibre optic cable deployed inside coiled tubing

ABSTRACTA two‐dimensional walkaway vertical seismic profiling survey using distributed acoustic sensing was conducted at an onshore site in Japan. The maximum depth and the deviation of the observation well were more than 4,000 m and 81 degrees, respectively. Among the several methods for installing fibre optic cables, we adopted the inside coiled tubing method, in which coiled tubing containing a fibre optic cable is deployed. The signal‐to‐noise ratio of the raw shot gather was low, possibly due to poor coupling between the fibre optic cable and the subsurface formation resulting from the fibre optic cable deployment method and the existence of considerable tubewave noise. Nevertheless, direct P‐wave arrivals, P–P reflections and P–S converted waves exhibited acceptable signal‐to‐noise ratios after careful optimization of gauge length for distributed acoustic sensing optical processing and the application of carefully parameterized tubewave noise suppression. One of the challenges in current distributed acoustic sensing vertical seismic profile data processing is the separation of P‐ and S‐waves using only one‐component measurements. Hence, we applied moveout correction using two‐dimensional ray tracing. This process effectively highlights only reflected P‐waves, which are used in subsequent subsurface imaging. Comparison with synthetic well seismograms and two‐dimensional surface seismic data confirms that the final imaging result has a sufficiently high quality for subsurface monitoring. We acquired distributed acoustic sensing vertical seismic profile data under both flowing conditions and closed conditions, in which the well was shut off and no fluid flow was allowed. The two imaging results are comparable and suggest the possibility of subsurface imaging and time‐lapse monitoring using data acquired under flowing conditions. The results of this study suggest that, by adopting the inside coiled tubing method without drilling a new observation well, more affordable distributed acoustic sensing vertical seismic profile monitoring can be achieved in fields such as CO2 capture and storage and unconventional shale projects, where monitoring costs have to be minimized.

Ray‐based reflection traveltime tomography using approximate stationary points

ABSTRACTReflection traveltime tomography has been used to describe subsurface velocity structures which, in practice, can be used as a background or initial model for pre‐stack depth migration or full waveform inversion. Conventional reflection traveltime tomography is performed by solving an optimization problem based on a ray‐tracing method. As a result, reflection traveltime tomography requires heavy computational efforts to carry out ray tracing and solve a large matrix equation. In addition, like most data‐domain tomography methods, reflection traveltime tomography depends on initial guesses and suffers from non‐uniqueness and uncertainty of solutions. In this research, we propose a deterministic ray‐based reflection traveltime tomography method by applying seismic interferometry. This method does not suffer from the non‐uniqueness problem and does not require a priori information on subsurface media. By adding a virtual layer (whose properties are known) on top of the real surface and applying convolution‐type interferometry, we approximately determine the stationary points (i.e., incident raypaths in the virtual layer). Then, we generate reflection points for a range of assumed velocities and estimate the velocity by considering the number of reflection points and the traveltime difference between the observed and calculated data. The reflection surface can then be recovered by using the estimated velocity. Once the first target layer is resolved, we can recover the whole media by recursively applying the same method to the lower layers. Numerical examples using surface seismic profile data for homogeneous‐layer (with a low‐velocity layer) and inhomogeneous‐layer models and real field data experiments on the Congo data set demonstrate that our method can successfully recover the velocities and depths of subsurface media without initial guesses. However, our method has some limitations for multi‐layer models because the method does not have sufficient reflection points for the deeper layers.

Seismic depth imaging of iron‐oxide deposits and their host rocks in the Ludvika mining area of central Sweden

ABSTRACTThe development of cost‐effective and environmentally acceptable geophysical methods for the exploration of mineral resources is a challenging task. Seismic methods have the potential to delineate the mineral deposits at greater depths with sufficiently high resolution. In hardrock environments, which typically host the majority of metallic mineral deposits, seismic depth‐imaging workflows are challenged by steeply dipping structures, strong heterogeneity and the related wavefield scattering in the overburden as well as the often limited signal‐to‐noise ratio of the acquired data. In this study, we have developed a workflow for imaging a major iron‐oxide deposit at its accurate position in depth domain while simultaneously characterizing the near‐surface glacial overburden including surrounding structures like crossing faults at high resolution. Our workflow has successfully been showcased on a 2D surface seismic legacy data set from the Ludvika mining area in central Sweden acquired in 2016. We applied focusing prestack depth‐imaging techniques to obtain a clear and well‐resolved image of the mineralization down to over 1000 m depth. In order to account for the shallow low‐velocity layer within the depth‐imaging algorithm, we carefully derived a migration velocity model through an integrative approach. This comprised the incorporation of the tomographic near‐surface model, the extension of the velocities down to the main reflectors based on borehole information and conventional semblance analysis. In the final step, the evaluation and update of the velocities by investigation of common image gathers for the main target reflectors were used. Although for our data set the reflections from the mineralization show a strong coherency and continuity in the seismic section, reflective structures in a hardrock environment are typically less continuous. In order to image the internal structure of the mineralization and decipher the surrounding structures, we applied the concept of reflection image spectroscopy to the data, which allows the imaging of wavelength‐specific characteristics within the reflective body. As a result, conjugate crossing faults around the mineralization can directly be imaged in a low‐frequency band while the internal structure was obtained within the high‐frequency bands.

Anisotropic Kirchhoff pre-stack depth migration at the COSC-1 borehole, central Sweden

SUMMARYA remarkably well preserved representation of a deeply eroded Palaeozoic orogen is found in the Scandinavian Caledonides, formed by the collision of the two palaeocontinents Baltica and Laurentia. Today, after 400 Ma of erosion along with uplift and extension during the opening of the North Atlantic Ocean, the geological structures in central western Sweden comprise far transported allochthonous units, the underlying Precambrian crystalline basement, and a shallow west-dipping décollement that separates the two and is associated with a thin layer of Cambrian black shales. These structures, in particular the Seve Nappes (upper part of the Middle Allochthons), the Lower Allochthons and the highly reflective basement are the target of the two approximately 2.5 km deep fully cored scientific boreholes in central Sweden that are part of the project COSC (Collisional Orogeny in the Scandinavian Caledonides). Thus, a continuous 5 km tectonostratigraphic profile through the Caledonian nappes into Baltica’s basement will be recovered. The first borehole, COSC-1, was successfully drilled in 2014 and revealed a thick section of the seismically highly reflective Lower Seve Nappe. The Seve Nappe Complex, mainly consisting of felsic gneisses and mafic amphibolites, appears to be highly anisotropic. To allow for extrapolation of findings from core analysis and downhole logging to the structures around the borehole, several surface and borehole seismic experiments were conducted. Here, we use three long offset surface seismic profiles that are centred on the borehole COSC-1 to image the structures in the vicinity of the borehole and below it. We applied Kirchhoff pre-stack depth migration, taking into account the seismic anisotropy in the Seve Nappe Complex. We calculated Green’s functions using an anisotropic eikonal solver for a VTI (transversely isotropic with vertical axis of symmetry) velocity model, which was previously derived by the analysis of VSP (Vertical Seismic Profile) and surface seismic data. We show, that the anisotropic results are superior to the corresponding isotropic depth migration. The reflections appear significantly more continuous and better focused. The depth imaging of the long offset profiles provides a link between a high-resolution 3-D data set and the regional scale 2-D COSC Seismic Profile and complements these data sets, especially in the deeper parts below the borehole. However, many of the reflective structures can be observed in the different data sets. Most of the dominant reflections imaged originate below the bottom of the borehole and are situated within the Precambrian basement or at the transition zones between Middle and Lower Allochthons and the basement. The origin of the deeper reflections remains enigmatic, possibly representing dolerite intrusions or deformation zones of Caledonian or pre-Caledonian age.

Detecting and characterising an englacial conduit network within a temperate Swiss glacier using active seismic, ground penetrating radar and borehole analysis

ABSTRACTEnglacial hydrology plays an important role in routing surface water to the glacier's bed and it consequently affects the glacier's dynamics. However, it is often difficult to observe englacial conduit conditions on temperate glaciers because of their short-lived nature. We acquired repeated active surface seismic data over the Rhone Glacier, Switzerland to monitor and characterise englacial conduit conditions. Amplitude-versus-angle analysis suggested that the englacial conduit is water filled and between 0.5 and 4 m thick. A grid of GPR profiles, acquired during the 2018 melt season, showed the englacial conduit network persisting and covering ~ 14,000 m2. In late summer 2018, several boreholes were drilled into the conduit network. We observed generally stable water pressure, but there were also short sudden increases. A borehole camera provided images of a fast flowing englacial stream transporting sediment through the conduit. From these observations, we infer that the englacial conduit network is fed by surface meltwater and morainal streams. The surface and morainal streams merge together, enter the glacier subglacially and flow through subglacial channels along the flank. These subglacial channels flow into highly efficient englacial conduits traversing the up-glacier section of the overdeepening before connecting with the subglacial drainage system.

Amplitude variation with incident angle and azimuth inversion for Young's impedance, Poisson's ratio and fracture weaknesses in shale gas reservoirs

ABSTRACTBy analogy with P‐ and S‐wave impedances, the product of Young's modulus and density can be termed as Young's impedance, which indicates the rock lithology and brittleness of unconventional hydrocarbon reservoirs. Poisson's ratio is also an effective indicator of rock brittleness and fluid property of unconventional reservoirs, and fracture weaknesses indicate the fracture properties (fracturing intensity and fracture fillings) in fracture‐induced unconventional reservoirs. We aim to simultaneously estimate the Young's impedance, Poisson's ratio and fracture weaknesses from wide‐azimuth surface seismic data in a fracture‐induced shale gas reservoir, and use the horizontal transversely isotropic model to characterize the fractures. First, the linearized PP‐wave reflection coefficient in terms of Young's impedance, Poisson's ratio, density and fracture weaknesses is derived for the case of a weak‐contrast interface separating two weakly horizontal transversely isotropic media. In addition, an orthorhombic anisotropic case is also discussed in this paper. Then a Bayesian amplitude variation with incident angle and azimuth scheme with a model constraint is used to stably estimate Young's impedance, Poisson's ratio and fracture weaknesses with only PP‐wave azimuthal seismic data. The proposed approach is finally demonstrated on both synthetic and real data sets with reasonable results.

An introduction to Marchenko methods for imaging

Geoscientists often have little information about earth’s subsurface heterogeneities prior to mapping them using seismic or other geophysical data. Marchenko methods are a set of novel, data-driven techniques that help us to project surface seismic data to points in the subsurface, to form seismograms as though they had been created at each point. In so doing, Marchenko methods account for many of the complex, multiply reflected seismic wave interactions that take place in the real earth’s subsurface. The resulting seismograms are the information required to create subsurface images that are more accurate than standard methods. Our aim is to introduce these concepts with the minimum amount of mathematics required to understand how the Marchenko method can iterate to a solution and to provide a well-commented, easily editable MATLAB code package for demonstration and training purposes. Green’s function estimation using the Marchenko method is first illustrated for a constant velocity, variable density, 1D medium, with results that indicate a near-perfect match when compared with true, synthetically modeled solutions. Similar quality results are shown for variable velocity, 2D Green’s function estimation. Finally, we determine how these estimates could be used to create images of the subsurface, which, when compared with standard methods, contain reduced contamination due to multiple-related artifacts. Our code package includes the 2D data set required to reconstruct the relevant figures that we present, and it allows for experimentation with the implementation of the Marchenko method and the application of Marchenko imaging.

Appraising structural interpretations using seismic data — Theoretical elements

Structural interpretation of seismic images can be highly subjective, especially in complex geologic settings. A single seismic image will often support multiple geologically valid interpretations. However, it is usually difficult to determine which of those interpretations are more likely than others. We have referred to this problem as structural model appraisal. We have developed the use of misfit functions to rank and appraise multiple interpretations of a given seismic image. Given a set of possible interpretations, we compute synthetic data for each structural interpretation, and then we compare these synthetic data against observed seismic data; this allows us to assign a data-misfit value to each structural interpretation. Our aim is to find data-misfit functions that enable a ranking of interpretations. To do so, we formalize the problem of appraising structural interpretations using seismic data and we derive a set of conditions to be satisfied by the data-misfit function for a successful appraisal. We investigate vertical seismic profiling (VSP) and surface seismic configurations. An application of the proposed method to a realistic synthetic model shows promising results for appraising structural interpretations using VSP data, provided that the target region is well-illuminated. However, we find appraising structural interpretations using surface seismic data to be more challenging, mainly due to the difficulty of computing phase-shift data misfits.

Assessment of gas hydrate accumulations using velocities derived from vertical seismic profiles and acoustic log data in Krishna-Godavari Basin, India

The second Indian National Gas Hydrate Program Expedition (NGHP-02) was executed in 2015 in four areas termed as Areas A, B, C and E. During this expedition, twenty five research sites were drilled and/or cored in Krishna-Godavari (KG) and Mahanadi Basins, eastern Indian offshore. During NGHP-02, zero offset vertical seismic profile (VSP) data were acquired at three sites: Sites NGHP-02-17, −19 and −22 in Area B of the KG Basin. In this study, we focus on the three sites in Area B of the KG Basin, where, zero-offset VSP and downhole acoustic log data are used to assess and characterize the gas hydrate deposits. Zero-offset VSP data are correlated with wireline log, surface seismic and synthetic seismic data to characterize and delineate gas hydrate accumulations in the KG Basin. Low velocities ranging from 1500 to 1650 m/s are observed in the unconsolidated shallow sedimentary section above gas hydrate-bearing units, whereas, very high velocities are observed in the acquired acoustic log and VSP data. In the gas hydrate-bearing sedimentary sections, the VSP derived interval velocities range from 2000 to 3000 m/s in the depth interval between 267 and 287 m below sea floor (mbsf) at Site NGHP-02-17, between 1650 and 1750 m/s in the depth interval between 306 and 366 mbsf at Site NGHP-02-19 and between 1700 and 1800 m/s in the depth interval between 198 and 290 mbsf at Site NGHP-02-22. Gas hydrates are distributed both as pore-filling and fracture-filling at all three sites, however, high concentrations are only observed as pore-filling morphology. We estimate the amount of gas hydrate considering both isotropic (pore-filling) and anisotropic (fracture-filling) acoustic reservoir models. Our estimations of gas hydrate saturation match well with the available pressure core data and suggest that high gas hydrate concentrations (to nearly 85% of pore space) are distributed in a load bearing morphology.