3D Vertical Seismic Profile Data Research Articles

Estimation of P‐wave anisotropy parameters from 3D vertical seismic profile with distributed acoustic sensors and geophones for seismic imaging in the CO2CRC Otway Project

ABSTRACTThe quality and accuracy of a seismic image can be significantly affected by anisotropy. When anisotropy is significant, neglecting it can lead to smearing of the image, dispositioning of reflections and distortion of amplitudes. Thus, it is imperative to estimate anisotropy and take it into account, especially for long‐offset or wide‐azimuthal seismic data. This study estimates P‐wave anisotropy parameters at the Otway site (Victoria, Australia). A wide range of available offsets acquired within the CO2CRC Otway Project provides a unique opportunity for anisotropy estimation from 3D vertical seismic profile data. We estimate P‐wave anisotropy from direct‐wave arrivals in vertical seismic profile data acquired with geophones and distributed acoustic sensors installed in two wells. Data analysis reveals seismic anisotropy of the subsurface with a significant presence of both polar and azimuthal anisotropy. We estimate key parameters such as normal moveout velocity, azimuthal ellipticity, polar anellipticity and fast‐velocity azimuth by nonlinear fitting of the analytical travel‐time approximation to observed direct P‐wave travel times from 3D vertical seismic profile data. Obtained anisotropy parameters show that polar anellipticity remains almost constant and equal to 0.1 for the whole depth range, while azimuthal anisotropy changes significantly with depth: it is relatively weak in the shallow section then increases significantly below a depth of 600 m. The fast‐velocity azimuth coincides with the orientation of the maximum horizontal stress in the study area. The results show that despite their low sensitivity for large offsets, the distributed acoustic sensor receivers provide sufficient information on anisotropic travel times over the entire length of the well, which is critical for reflection imaging from both vertical seismic profile and surface seismic data.

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.

Fractures extraction and associated intensity maps from 3D VSP data

Fractures and faults were extracted from a reverse time migrated 3D Vertical Seismic Profile (VSP) data acquired over a carbonate reservoir offshore Abu Dhabi in the United Arab Emirates. A specifi...

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.

Extraction and characterization of faults and fractures from 3D VSP data in a carbonate reservoir: A workflow

We present a workflow for the extraction and characterization of fractures and faults using a Reverse Time Migrated (RTM) volume from 3D Vertical Seismic Profile data (3D VSP) acquired in an oilfield offshore Abu Dhabi in the United Arab Emirates. The workflow consists of: preconditioning of the input RTM volume, which involves removal of acquisition footprints; extraction of faults and fractures using a semblance based discontinuity attribute; binary filtering and clustering for characterization and interpretation using prior geological information, as well as removals of unwanted features such as those related to stratigraphy; and finally interpretation. Complex networks of lineaments were extracted after application of the workflow. The location of lineaments with length greater than 200 m and orientated WNW-ESE to NW-SE correlates with a known flower structure which has a trend similar to that of the Proterozoic Najd Fault System that cut the Arabian Peninsula. Lineaments with strike directions ENE-WSW and NE-SW are interpreted to be related to reactivation of basement faults and correspond to the Hormuz Salt basin's major trend in the Arabian Gulf. Dominant strike directions of lineaments at three reservoir levels correlate with dominant strike directions of interpreted fractures from Fullbore Formation Microimager (FMI) and core data; thus implying that they are likely related to fractures or fracture corridors. Lineaments with orientation NNE-SSW correlate with closed fractures while lineaments with orientation NNW-SSE correlate with open fractures. Zones with relatively high fracture intensity are generally located north and north-west of the VSP well in the reservoir zones. The good correlation of the results with interpreted fractures from core and FMI data shows the robustness of the workflow and gives confidence to the results.

A high-density, high-resolution joint 3D VSP–3D surface seismic case study in the Canadian oil sands

This Canadian oil sands case history illustrates how a high-density, high-resolution joint 3D vertical seismic profile (VSP)–3D surface seismic survey was designed, acquired, and processed to successfully meet the objective of obtaining a detailed image of the subsurface, including the cap rock, the internal architecture of the oil sands reservoir, the underlying carbonates, and the fault and fracture network that runs from surface to basement. The VSP-driven processing was essential in determining the effects of attenuation, multiples, and converted waves, and in quantifying the anisotropy for imaging and time-to-depth conversion. The joint 3D tomography inversion of the VSP and surface seismic data provided an accurate velocity model to migrate the 3D surface seismic data and the 3D VSP data in depth. Each of the 28 wells located within the survey area tied in to the final seismic volume very well. Depth imaging resolved the shallow velocity variations that the initial time processing could not. The apparent (but erroneous) azimuthal velocity effects in the time processing were minimized in the depth processing, resulting in an anisotropy velocity model that was in accordance with the 3D VSP data. A 3D full-waveform inversion test complemented this case history.

Imaging the Aquistore reservoir after 36 kilotonnes of CO2 injection using distributed acoustic sensing

Aquistore is a geologic [Formula: see text] storage project that is using a deep saline formation as a storage reservoir. From April 2015 to February 2016, approximately 36 kilotonnes of [Formula: see text] were injected into the reservoir at a depth of 3130–3350 m. We have developed an analysis of distributed acoustic sensing (DAS) 3D vertical seismic profiling data acquired in February 2016, marking the first seismic survey since injection began. The VSP data were processed in parallel with baseline preinjection data from a November 2013 survey, with the objective of detecting and characterizing the subsurface [Formula: see text] plume and evaluating the repeatability of DAS in a reservoir monitoring project. A single processing sequence was devised that (1) accurately imaged the reservoir for the baseline and monitor data and (2) attained adequate repeatability to observe time-lapse differences related to the presence of [Formula: see text]. Repeatability was somewhat compromised by the less advanced noise cancellation methodology of the DAS system used for the baseline survey. In the final cross-equalized migrated data volumes, normalized root-mean-square ([Formula: see text]rms) difference values of [Formula: see text] were attained at the reservoir level indicating good repeatability compared with most surface seismic studies. An injection-related amplitude anomaly with maximum [Formula: see text]rms values of approximately 0.7 is apparent in the Deadwood Formation of the reservoir, whereas no significant [Formula: see text]rms anomalies were observed near the injection and monitoring wells in the Black Island Member or above the reservoir.

Reverse time migration of 3D vertical seismic profile data

Reverse time migration (RTM) has shown increasing advantages in handling seismic images of complex subsurface media, but it has not been used widely in 3D seismic data due to the large storage and computation requirements. Our prime objective was to develop an RTM strategy that was applicable to 3D vertical seismic profiling (VSP) data. The strategy consists of two aspects: storage saving and calculation acceleration. First, we determined the use of the random boundary condition (RBC) to save the storage in wavefield simulation. An absorbing boundary such as the perfect matching layer boundary is often used in RTM, but it has a high memory demand for storing the source wavefield. RBC is a nonabsorbing boundary and only stores the source wavefield at the two maximum time steps, then repropagates the source wavefield backwards at every time step, and hence, it significantly reduces the memory requirement. Second, we examined the use of the graphic processing unit (GPU) parallelization technique to accelerate the computation. RBC needs to simulate the source wavefield twice and doubles the computation. Thus, it is very necessary to realize the RTM algorithm by GPU, especially for a 3D VSP data set. GPU and central processing unit (CPU) collaborated parallel implementation can greatly reduce the computation time, where the CPU performs serial code, and the GPU performs parallel code. Because RBC does not need the same huge amount of storage as an absorbing boundary, RTM becomes practically applicable for 3D VSP imaging.

Dual-well 3D vertical seismic profile enabled by distributed acoustic sensing in deepwater Gulf of Mexico

We have acquired and processed 3D vertical seismic profile (VSP) data recorded simultaneously in two wells using distributed acoustic sensing (DAS) during the acquisition of the 2012 Mars 4D ocean-bottom seismic survey in the deepwater Gulf of Mexico. The objectives of the project were to assess the quality of DAS data recorded in fiber-optic cables from the surface to the total depth, to demonstrate the efficacy of the DAS VSP technology in a deepwater environment, to derisk the use of the technology for future water injection or production monitoring without intervention, and to exploit the velocity information that 3D VSP data provide for evaluating and updating the velocity model. We evaluated the advantages of DAS VSP to reduce costs and intrusiveness, and we determined that high-quality images can be obtained from relatively noisy raw 3D DAS VSP data, as evidenced by the well 1 image, probably the best 3D VSP image we have ever seen. Our results also revealed that the direct arrival traveltimes can be used to assess the quality of an existing velocity model and to invert for an improved velocity model. We identified issues with the DAS acquisition and the processing steps to mitigate them and to handle problems specific to DAS VSP data. We described the steps for conditioning the data before migration, reverse time migration, and postmigration processing to reduce noise artifacts. We outlined a novel first-break picking procedure that works even in the absence of a strong first arrival and a velocity diagnosis method to assess and validate velocity models and velocity updates. Finally, we determined potential applications to 4D monitoring of fluid movement around producer or injector wells, identification of active salt movements, and more accurate imaging and monitoring of complex structures around the wells.

Inversion of multicomponent 3D vertical seismic profile data for porosity and CO2 saturation at the Cranfield injection site, Cranfield, MS

Studying how injected [Formula: see text] affects the seismic response of reservoir rocks is important because it can improve subsurface characterization where [Formula: see text] injection is taking place. This study uses multicomponent data from a 3D vertical seismic profile (VSP) and well logs to model and invert probabilistically for the porosity and [Formula: see text] saturation at the Cranfield reservoir. The well logs were used to calibrate a rock-physics model. Once the accuracy of the model was verified, P-impedance and [Formula: see text]/[Formula: see text] from inverted multicomponent VSP data were used to estimate the porosity and fluid saturation. This inversion generated probabilistic estimates of porosity and fluid saturation for the area of the reservoir sampled by PP- and PS-waves. Inversion results using the measured well log data for calibration indicated that the model was able to estimate porosity with a relatively high degree of accuracy, with the root-mean-square (rms) error being less than 3% for all calibration tests. Pore-fluid composition was estimated, however, with reduced accuracy, with rms errors ranging from 6% to 22% depending on the composition of the calibration fluid. Results from integrating the multicomponent VSP data with the rock-physics model indicated that estimated reservoir porosities are quite close to measured values at an observation well. Pore-fluid composition estimates indicated that this method can differentiate between areas containing [Formula: see text] and those that do not.

Anisotropic frequency-dependent spreading of seismic waves from first-arrival vertical seismic profile data analysis

A model of first-arrival amplitude decay combining geometric spreading, scattering, and inelastic dissipation is derived from a multioffset, 3D vertical seismic profile data set. Unlike the traditional approaches, the model is formulated in terms of path integrals over the rays and without relying on the quality factor ([Formula: see text]) for rocks. The inversion reveals variations of geometric attenuation (wavefront curvatures and scattering, [Formula: see text]) and the effective attenuation parameter ([Formula: see text]) with depth. Both of these properties are also found to be anisotropic. Scattering and geometric spreading (focusing and defocusing) significantly affect seismic amplitudes at lower frequencies and shallower depths. Statistical analysis of model uncertainties quantitatively measures the significance of these results. The model correctly predicts the observed frequency-dependent first-arrival amplitudes at all frequencies. This and similar models can be applied to other types of waves and should be useful for true-amplitude studies, including inversion, inverse [Formula: see text]-filtering, and amplitude variations with offset analysis. With further development of petrophysical models of internal friction and elastic scattering, attenuation parameters [Formula: see text] and [Formula: see text] should lead to constraints on local heterogeneity and intrinsic physical properties of the rock. These parameters can also be used to build models of the traditional frequency-dependent [Formula: see text] for forward and inverse numerical viscoelastic modeling.

Anisotropic attenuation analysis of crosshole data generated during hydraulic fracturing

Attenuation of seismic waves is sensitive to the physical properties of the subsurface and has been observed in vertical seismic profiling (VSP) and reflection data. De et al. (1994) report measurements of the P- and S-wave quality factors from VSP surveys and sonic logs. Klimentos (1995) measures compressional and shear attenuation from sonic logs in sandstone formations with variable oil, water, and gas saturation and observes that [Formula: see text] and [Formula: see text] can be used for pore-fluid discrimination. Maultzsch et al. (2007) evaluate P-wave azimuthal attenuation anisotropy from 3D VSP data acquired over a fractured hydrocarbon reservoir and infer fracture directions from attenuation analysis. Attenuation anisotropy has also been observed in P-wave reflection data (Clark et al., 2009; Vasconcelos and Jenner, 2005). Seismic attenuation is most commonly measured using the spectral-ratio method. Zhu et al. (2007) extend the spectral-ratio method to anisotropic media and apply it to physical modeling data acquired for a transversely isotropic (TI) sample. Computing spectral ratios helps eliminate the source spectrum and can be used to obtain accurate effective and interval attenuation coefficients of P- and S-waves in layered anisotropic media (Behura and Tsvankin, 2009a; Shekar and Tsvankin, 2011).

Application of 3D vertical seismic profile multi‐component data to tight gas sands‡

ABSTRACTDue to the complicated geophysical character of tight gas sands in the Sulige gasfield of China, conventional surface seismic has faced great challenges in reservoir delineation. In order to improve this situation, a large‐scale 3D‐3C vertical seismic profiling (VSP) survey (more than 15 000 shots) was conducted simultaneously with 3D‐3C surface seismic data acquisition in this area in 2005. This paper presents a case study on the delineation of tight gas sands by use of multi‐component 3D VSP technology. Two imaging volumes (PP compressional wave; PSv converted wave) were generated with 3D‐3C VSP data processing. By comparison, the dominant frequencies of the 3D VSP images were 10–15 Hz higher than that of surface seismic images. Delineation of the tight gas sands is achieved by using the multi‐component information in the VSP data leading to reduce uncertainties in data interpretation. We performed a routine data interpretation on these images and developed a new attribute titled ‘Centroid Frequency Ratio of PSv and PP Waves’ for indication of the tight gas sands. The results demonstrated that the new attribute was sensitive to this type of reservoir. By combining geologic, drilling and log data, a comprehensive evaluation based on the 3D VSP data was conducted and a new well location for drilling was proposed. The major results in this paper tell us that successful application of 3D‐3C VSP technologies are only accomplished through a synthesis of many disciplines. We need detailed analysis to evaluate each step in planning, acquisition, processing and interpretation to achieve our objectives. High resolution, successful processing of multi‐component information, combination of PP and PSv volumes to extract useful attributes, receiver depth information and offset/ azimuth‐dependent anisotropy in the 3D VSP data are the major accomplishments derived from our attention to detail in the above steps.

Seismic Monitoring and Verification for the CO2CRC Otway Basin Project, Part 2: acquisition and analysis of borehole seismic data

Abstract The Otway Project conducted under the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO 2 CRC) is the first of its kind, where CO 2 is injected into a depleted gas reservoir. The use of depleted fields for CO 2 storage is likely to become widely adopted globally and, therefore, the project will provide important experience for monitoring under these conditions. However, such scenario is not favorable for the application of geophysical techniques for the purpose of CO 2 monitoring and verification (M&V) because the injection of CO 2 into a CH4 depleted reservoir is modeled to produce very subtle changes in elastic properties of the reservoir rock which may be very difficult to measure. Consequently geophysical program for the Otway site was design according to the expected time-lapse effects. It combines both surface and borehole seismic methods. Surface seismic should provide a global vision of the underground and an indirect confirmation of the CO 2 containment by recording no differences between the successive time-lapse experiments. Vertical Seismic Profile (VSP) surveys are expected to provide an improved characterization of the reservoir and hopefully a direct indication of the fluid distribution and/or its potential upward migration along the reservoir bounding fault pattern. Indeed the results of the current analysis of both pre-base line (test) and base-line 2D and 3D VSP data are encouraging. The availability of vector wave field (three-component) data recorded in VSP surveys should significantly improve the outcomes of M&V program at Naylor site.

Parsimonious migration of 3-C 3D VSP data

Conventional Kirchhoff migration can be made much faster by a priori calculation of wave arrival directions, and tracing rays back only along the measured directions; this is known as parsimonious migration. For surface seismic data, where acquisition with 2D arrays is common, the wave arrival directions can be measured by using local slant stacking to calculate the two horizontal slowness components. The vertical slowness is then deduced by using the dispersion relation. For vertical seismic profile (VSP) data, where multiline acquisition is not possible, only the vertical component of the slowness vector can be measured, which is insufficient to constrain the wave arrival direction. We overcome this limitation for three-component VSP data by polarization analysis of the incident waves. Polar and azimuth anglesare calculated at the receivers by estimating the data covariance matrix and the vertical slowness, assuming isotropic media and linear polarization of both P- and S-waves. For P-waves, the data covariance matrix defines the polarization ellipsoid, which is then used to calculate the wave arrival direction. For S-waves, an additional step is required because the polarization is orthogonal to the propagation direction. Ray tracing along only the measured propagation directions eliminates the traditional traveltime table calculation, and enhances the efficiency of Kirchhoff migration of three-component VSP data. Distortions of the polarization caused by factors such as anisotropy are assumed to be corrected independently of the migration process described here. Synthetic examples for a flat reflector and for a salt flank model demonstrate the procedure and the image quality.

The use of VSP techniques for fault zone characterization: An example from the San Andreas Fault

Vertical seismic profiling (VSP) technology is increasingly being used in the fields of earthquake seismology and tectonics. This is motivated in part by the growing number of oil field microseismic monitoring surveys, but more so by projects that involve drilling deep wells for monitoring crustal activity at depth. Examples of these projects are the San Andreas Fault Observatory at Depth (SAFOD), the Nankai Trough Seismogenic Zone Experiment, the Gulf of Corinth Rift Laboratory, and the Taiwan Chelungpu Fault Drilling Project, and other projects by the International Continental and Ocean Drilling Programs (ICDP and IODP). These projects require instrumentation and surveying in deep and possibly hot borehole environments. With higher resolution than surface seismic data, images from 2D and 3D VSP data contribute to better characterization and interpretation of complex reservoirs at smaller scales. The location of receivers in the low-noise borehole environment yields higher signal-to-noise ratios, higher ...