Offset Vertical Seismic Profile Research Articles

Development of a subsea distributed acoustic sensing acquisition system

Over the past few decades, distributed acoustic sensing (DAS) data acquisition has seen great improvements from better interrogators, engineered fiber, and lessons learned from subsea installation and acquisition. This has given us confidence that DAS cables can be installed in wells with subsea trees to be used as receivers for vertical seismic profile (VSP) seismic imaging. VSP imaging for deepwater fields has been demonstrated to provide better illumination and higher-frequency seismic data. Permanent DAS cable installation can be used to acquire highly repeatable time-lapse (4D) data. DAS cables have been installed in a number of subsea wells on two deepwater oil fields with the intention of covering the crest of these fields with high-frequency seismic data. A system has been developed to allow for DAS acquisition on these offshore subsea wells with long-distance tie backs using permanently installed interrogators on the floating platforms and engineered fiber in the wells. On each of these fields, a DAS cable has now been installed, and subsequently, a zero offset (ZO) DAS VSP has been acquired for verification and commissioning. These ZO DAS VSP acquisitions indicate high-fidelity installations resulting in DAS VSP data with excellent data quality. These first subsea DAS acquisitions indicate great promise, and further installations and acquisitions are planned with the ultimate goal of providing high-frequency seismic images over the crest of these fields to reduce the uncertainty in decisions around reservoir management and future infill drilling.

Processing of multi‐well offset vertical seismic profile data acquired with distributed acoustic sensors and surface orbital vibrators: Stage 3 of the CO2CRC Otway Project case study

ABSTRACTTime‐lapse seismic reservoir monitoring is used as a way to gain insight into subsurface processes. Yet, the application of standard 4D technology onshore faces challenges, such as high cost, significant environmental footprint and, consequently, relatively infrequent surveys. As part of the Otway Project Stage 3 CO2 injection study, continuous automated borehole‐based monitoring using distributed acoustic sensing has been paired with permanently deployed surface sources, referred to as surface orbital vibrators, as a way to monitor the spreading CO2 plume. The injection of 15,000 tonnes of CO2 in a saline reservoir at a depth of 1550 m is monitored using five boreholes instrumented with enhanced sensitivity fibre optic cables and nine surface orbital vibrators, creating an array of 45 well–source pairs. The data are processed with an offset vertical seismic profiling processing workflow developed to address key challenges of the continuous distributed acoustic sensing acquisition using surface orbital vibrators. The processing flow includes deconvolution with a source sweep recorded by a pilot geophone installed below the surface orbital vibrators. A second deconvolution with a wavelet estimated from direct arrivals compensates for the difference between distributed acoustic sensing measurements and the pilot geophone as well as near‐surface variations. Image quality is noted to be best for short offsets and decreases with increasing offsets and well deviations. As surface orbital vibrators generate unique sweeps in two rotation directions, further processing is applied to stack these rotation signals together, which further improves the images. The resulting 2D transects of each well–source pair visually provide good illumination of the subsurface, suggesting continuous monitoring of the spreading CO2 plume should be possible with some further tuning of the processing workflow for time‐lapse repeatability.

Geophysical monitoring using active seismic techniques at the Citronelle Alabama CO2 storage demonstration site

Between August 2012 and September 2014, about 114,000 metric tonnes of CO2 was captured from the coal-fired Plant Barry Power Station at Bucks Alabama and injected into the Paluxy Formation above the oil pool in the southeast unit of the Citronelle Oilfield. Various monitoring methods were deployed at land surface and in project wells to measure system performance, comply with permit requirements and test new and innovative monitoring tools. The monitoring program relied heavily on active seismic methods for subsurface imaging of geologic structure and time-lapse seismic techniques to track the CO2 migration in the injection interval. Both conventional geophone/hydrophone and fiber-optic based Distributed Acoustic Sensing (DAS) arrays were deployed and tested, allowing a side by side comparison of the equipment and techniques.Geophysical imaging of the subsurface was successful using DAS in the offset vertical seismic profile (OVSP) survey configuration. A high resolution OVSP image of the subsurface was obtained in 2014 with DAS, which exceeded project expectations in comparison to a lower resolution image obtained in 2012 using a conventional 80-level geophone array. A time-lapse image of the redistribution of CO2 after injection ended in September 2014 was obtained with two DAS OVSP surveys from June 2014 and December 2015, thus successfully demonstrating its proof-of-concept. Unfortunately, a pre-injection baseline survey with DAS, which was in its initial stage of technology development in 2012, did not have sufficient quality for use, making it difficult to interpret the acquired DAS time-lapse difference. Additional research in this area has since demonstrated the utility of time-lapse DAS OVSP. DAS data were also acquired during a cross-well seismic survey conducted in 2014. Unfortunately, the DAS technique was not success in the cross-well survey configuration because the system noise level was too high in the crosswell frequency output range (100–1200 Hz) of the piezoelectric source (increasing by a factor of ten compared to VSP frequency band). Additionally, the cross-well geometry causes sub-horizontal (broadside) incidence on the vertical DAS fiber cable, which is known to be problematic. Current research is focused on improving the DAS cable response to broadside acoustic energy.Time-lapse seismic surveys using commercially available conventional arrays were also acquired. In contrast to the DAS acquired data, the cross-well seismic results obtained with the conventional array was highly successful and clearly showed the CO2 remained in zone at the end of injection. Time-lapse differencing of the OSVP surveys acquired with the conventional arrays proved to be inconclusive. Changes in wellbore conditions between surveys and unavoidable changes in equipment (the array used for the baseline survey was retired) affected data quality, making it difficult to interpret the OVSP results.

P- and S-mode separation of three-component VSP data

ABSTRACTIn an offset vertical seismic profile (VSP), elastic wavefields are recorded in three orthogonal components. For a given wave mode P, SV or SH, the amplitude is distributed among the three components because observations close to the target layer enable numerous seismic waves with large emergent angles to be recorded. Therefore, in VSP P and S mode separation, it is necessary to extract the same wave mode from every component and restore its true amplitude, rather than simply removing the P-wave projection from the horizontal component or the S-wave projection from the vertical component. Thus, we investigate a two-step method of VSP wave mode separation in which it is assumed that the P and SV (or SH) modes are not polarised orthogonally. First, the Z- and R-components are rotated into the nonorthogonal polarisation directions of the PV- and SV-waves. Here, the PV-wave is the P-mode projection onto the vertical–radial plane. The PV- and T-components are rotated into the nonorthogonal polarisation directions of the P- and SH-waves. To derive true polarisation directions for each component rotation, we employ a least-squares approach utilising the wave particle motions in different quadrants, which can determine the polarisation direction even under noisy conditions. Synthetic data test and application to VSP data from a coalfield reveal the stability and effectiveness of our method.

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.

English

The Niger Delta is a sedimentary deposit with continuing sediment deposition to date. In a stratified earth, seismic waves tend to propagate faster along layers than across layer boundaries. Shales, due to the clay minerals they contain, exhibit similar behavior. As a result, velocities derived from surface seismic are often faster than well-derived velocities, causing depths of structures from surface seismic interpretations to be much shallower than their true depths. Reservoir characterization workflows such as amplitude-versus offset (AVO) analysis, seismic inversion and pore pressure prognosis, which make use of seismic velocities to accurately delineate and define exploration targets, would be seriously impacted if velocity anisotropy is not quantified and the seismically-derived velocities corrected. Accurate quantification and correction of velocity anisotropy requires the use of offset vertical seismic profile (VSP) data to aid the estimation of the Thomsen’s anisotropic parameters, and . Unfortunately, such data are rarely acquired in many exploration projects and when they are available, they are often limited in areal coverage. In this study, an integrated approach using well and seismic data, based on the degree to which check shot and stacking interval velocity trends diverge with increasing depths, was utilized to quantify and correct seismically-derived velocity in AMFO field for improved quantitative seismic interpretation. Estimated anisotropy is between 2 and 22%, and becomes apparent at about 1,100 m true vertical depth subsea (TVDss). Key words: Velocity anisotropy, interval velocity, vertical seismic profile (VSP), anisotropic parameters, well velocity.

Borehole seismic survey using multimode optical fibers in a hybrid wireline

Distributed Fiber Optic Sensing is increasingly recognized as a viable alternative to geophone arrays for the acquisition of borehole seismic data. The ability to deploy optical fibers into a well, either as a cable based intervention or as part of a completion string, allows for the entire wellbore to be surveyed with every source activation. This can dramatically reduce the operating time required to complete a normal survey as well as offering the opportunity to achieve much higher spatial coverage than is typical of current technologies. The ability to acquire borehole seismic data in a producing well without the need to disrupt production also offers significant benefits to the operator.Distributed acoustic sensing (DAS) is a novel technology that uses an optical fiber cable as a sensor for acoustic signals and can take almost any downhole fiber-optic installation or deployment and turn the fiber optic cable into a large downhole seismic array. This array can provide enhanced Vertical Seismic Profile (VSP) imaging and monitor fluids and pressures changes in the hydrocarbon production reservoir. Walkaway VSP data acquired over a former producing well in north eastern China provided a rich set of very high quality DAS Walkaway VSP data. A standard VSP data pre-processing workflow was applied, followed by prestack Kirchhoff time migration. In the DAS pre-processing step we were faced with additional and special challenges: strong coherent noise due to cable slapping and ringing along the borehole casing. In comparison with an earlier offset VSP data set using 327-levels acquired with conventional 3C downhole geophones in the same well, the final pre-processed DAS walkaway VSP has a larger vertical aperture resulting in a wider lateral image. The single well DAS Walkaway VSP images provide a good result with higher vertical and lateral resolution than the surface seismic in the objective area. The vertical well environment without the ability to effectively “clamp” the sensor to the borehole casing wall by touching, creates a unique set of challenges. Although earth signal was recorded with almost all the shots, there was also a considerable amount of noise. Much of the noise was due to the physical placement of the wireline in the well and expressed by slapping and ringing. This paper reports on lessons learned in the handling of the wireline cable and subsequent special DAS data processing steps developed to remediate some of the practical wireline deployment issues. Optical wireline cable as a conveyance of fiber optic cables for VSP in vertical wells will open the use of the DAS system to much wider applications.

Sub-surface geology and velocity structure of the Krafla high temperature geothermal field, Iceland: Integrated ditch cuttings, wireline and zero offset vertical seismic profile analysis

The Krafla geothermal area in northern Iceland comprises one of the best studied examples of a high temperature geothermal field associated with an active volcanic rift zone. Of key importance to improved resource exploration and development in volcanic areas such as Krafla, is the interpretation and understanding of the subsurface geology. Within this study we present results from an integrated analysis of the downhole volcanic stratigraphy from the K-18 borehole within the Krafla caldera based on combined wireline, ditch cuttings, and zero-offset VSP (vertical seismic profile) analyses. This study presents the first published sonic log velocity data from a high temperature geothermal borehole in Iceland and clearly demonstrates the importance of borehole velocity data for improving volcanic facies interpretations. The shallow subsurface geology of the K-18 site from c. 0–380m comprises an inter-layered sequence of sub-aerial basaltic lavas, hyaloclastites and tuffaceous lithologies of both felsic and basic composition, which are progressively replaced by basaltic sheet intrusions with increasing depth. An interval of variably basic to more evolved mixed tuffaceous facies is identified based on cuttings analysis, gamma and sonic velocities between c. 790–1120m depth. Discrete high sonic Vp units cut the lower c. 100m of this interval and are interpreted as either sheet intrusions or lava interiors. At c. 1800m, a sharp increase in P-wave velocity from c. 4.5 to c. 5.5km/s, represents the transition from a mixed lava and sheet intrusion dominated sequence, into a dense basic intrusion forming the local basement that persists to the bottom of the borehole at c. 2215m. Reduced travel time analysis of processed zero-offset VSP results reveal good correspondence with the major stratigraphic boundaries in the borehole, supporting the potential for VSP studies to robustly characterize complex volcanic stratigraphy in high temperature geothermal fields. Finally, the application of percentage-based ditch cuttings analyses methods for volcanic facies analysis in geothermal boreholes is tested and assessed to have future potential.

Time‐lapse full waveform inversion of vertical seismic profile data: Workflow and application to the CO2CRC Otway project

AbstractVertical seismic profile (VSP) is one of the technologies for monitoring hydrocarbon production and CO2 geosequestration. However, quantitative interpretation of time‐lapse VSP is challenging due to its irregular distribution of source‐receiver offsets. One way to overcome this challenge is to use full waveform inversion (FWI), which does not require regular offsets. We present a workflow of elastic FWI applied to offset vertical seismic profile data for the purpose of identification and estimation of time‐lapse changes introduced by injection of 15,000 t of CO2‐rich gas mixture at 1.5 km depth. Application of this workflow to both synthetic and field data shows that elastic FWI is able to detect and quantify the time‐lapse anomaly in P wave velocity with the magnitude of 100–150 m/s.

Walkaway VSP using multimode optical fibers in a hybrid wireline

Distributed acoustic sensing (DAS) is a novel technology that uses an optical fiber cable as a sensor for acoustic signals and can take almost any downhole fiber-optic installation or deployment and turn the fiber-optic cable into a large downhole seismic array. This array can provide enhanced vertical seismic profile (VSP) imaging and monitor fluids and pressure changes in the hydrocarbon-production reservoir. Walkaway VSP data acquired over a formerly producing well in northeastern China provided a rich set of high-quality DAS walkaway VSP data. A standard VSP data preprocessing workflow was applied, followed by prestack Kirchhoff time migration. In the DAS preprocessing step, we were faced with additional challenges: strong coherent noise due to cable slapping and ringing along the borehole casing. Compared with an earlier offset VSP data set using 327 levels acquired with conventional 3C downhole geophones in the same well, the final preprocessed DAS walkaway VSP has a larger vertical aperture, resulting in a wider lateral image. The single-well DAS walkaway VSP images provide a good result with higher vertical and lateral resolution than the surface seismic in the objective area. The vertical-well environment, which lacks the ability to effectively “clamp” the sensor to the borehole-casing wall by touching, creates a unique set of challenges. Although earth signal was recorded with almost all the shots, there was also a considerable amount of noise. Much of the noise was due to the physical placement of the wireline in the well and was expressed by slapping and ringing. Reported here are lessons learned in handling the wireline cable and subsequent special DAS data processing steps developed to remediate some of the practical wireline deployment issues. Optical wireline cable as a conveyance of fiber-optic cables for VSP in vertical wells will open the use of the DAS system to wider applications.

SV-P extraction and imaging for far-offset vertical seismic profile data

We have analyzed vertical seismic profile (VSP) data acquired across a Marcellus Shale prospect and found that SV-P reflections could be extracted from far-offset VSP data generated by a vertical-vibrator source using time-variant receiver rotations. Optimal receiver rotation angles were determined by a dynamic steering of geophones to the time-varying approach directions of upgoing SV-P reflections. These SV-P reflections were then imaged using a VSP common-depth-point transformation based on ray tracing. Comparisons of our SV-P image with P-P and P-SV images derived from the same offset VSP data found that for deep targets, SV-P data created an image that extended farther from the receiver well than P-P and P-SV images and that spanned a wider offset range than P-P and P-SV images do. A comparison of our VSP SV-P image with a surface-based P-SV profile that traversed the VSP well demonstrated that SV-P data were equivalent to P-SV data for characterizing geology and that a VSP-derived SV-P image could be used to calibrate surface-recorded SV-P data that were generated by P-wave sources.

Monitoring CO2 Storage at Cranfield, Mississippi with Time-Lapse Offset VSP – Using Integration and Modeling to Reduce Uncertainty

Abstract A time-lapse Offset Vertical Seismic Profile (OVSP) data set was acquired as part of a subsurface monitoring program for geologic sequestration of CO2. The storage site at Cranfield, near Natchez, Mississippi, is part of a detailed area study (DAS) site for geologic carbon sequestration operated by the U.S. Dept. of Energy's Southeast Regional Carbon Sequestration Partnership (SECARB). The DAS site includes three boreholes, an injection well and two monitoring wells. The project team selected the DAS site to examine CO2 sequestration multiphase fluid flow and pressure at the interwell scale in a brine reservoir. The time-lapse (TL) OVSP was part of an integrated monitoring program that included well logs, crosswell seismic, electrical resistance tomography and 4D surface seismic. The goals of the OVSP were to detect the CO2 induced change in seismic response, give information about the spatial distribution of CO2 near the injection well and to help tie the high-resolution borehole monitoring to the 4D surface data. The VSP data were acquired in well CFU 31-F1, which is the ∼3200 m deep CO2 injection well at the DAS site. A preinjection survey was recorded in late 2009 with injection beginning in December 2009, and a post injection survey was conducted in Nov 2010 following injection of about 250 kT of CO2. The sensor array for both surveys was a 50-level, 3-component, Sercel MaxiWave system with 15 m (49 ft) spacing between levels. The source for both surveys was an accelerated weight drop, with different source trucks used for the two surveys. Consistent time-lapse processing was applied to both data sets. Time-lapse processing generated difference corridor stacks to investigate CO2 induced reflection amplitude changes from each source point. Corridor stacks were used for amplitude analysis to maximize the signal-to-noise ratio (S/N) for each shot point. Spatial variation in reflectivity (used to ‘map’ the plume) was similar in magnitude to the corridor stacks but, due to relatively lower S/N, the results were less consistent and more sensitive to processing and therefore are not presented. We examined the overall time-lapse repeatability of the OVSP data using three methods, the NRMS and Predictability (Pred) measures of Kragh and Christie (2002) and the signal-to-distortion ratio (SDR) method of Cantillo (2011) . Because time-lapse noise was comparable to the observed change, multiple methods were used to analyze data reliability. The reflections from the top and base reservoir were identified on the corridor stacks by correlation with a synthetic response generated from the well logs. A consistent change in the corridor stack amplitudes from pre- to post-CO2 injection was found for both the top and base reservoir reflections on all ten shot locations analyzed. In addition to the well-log synthetic response, a finite-difference elastic wave propagation model was built based on rock/fluid properties obtained from well logs, with CO2 induced changes guided by time-lapse crosswell seismic tomography ( Ajo-Franklin et al., 2013 ) acquired at the DAS site. Time-lapse seismic tomography indicated that two reservoir zones were affected by the flood. The modeling established that interpretation of the VSP trough and peak event amplitudes as reflectivity from the top and bottom of reservoir is appropriate even with possible tuning effects. Importantly, this top/base change gives confidence in an interpretation that these changes arise from within the reservoir, not from bounding lithology. The modeled time-lapse change and the observed field data change from 10 shotpoints are in agreement for both magnitude and polarity of amplitude change for top and base of reservoir. Therefore, we conclude the stored CO2 has been successfully detected and, furthermore, the observed seismic reflection change can be applied to Cranfield's 4D surface seismic for spatially delineating the CO2/brine interface.

Full‐waveform inversion for macro velocity model reconstruction in look‐ahead offset vertical seismic profile: numerical singular value decomposition‐based analysis

ABSTRACTFull‐waveform inversion is currently considered as a potential tool for improving depth‐velocity models for areas with complex geology. It is well‐known that success of the inversion is very sensitive to the available low‐frequency content of the data. In the paper we investigate this issue considering a look‐ahead offset vertical seismic profile survey and applying singular value decomposition analysis of a linearized forward map as the main tool. We demonstrate with this technique the difference between the sequential full‐waveform inversion strategy and the original time‐domain approach proposed in the early 1980s. We emphasize the role of the lowest frequency in the data, which is necessary for reliable velocity model inversion in particular cases. Finally we show the existence of a trade‐off between the lowest frequency and a regularization parameter of the inversion procedure. The presented approach may be adapted to answer general questions regarding the quality of data and acquisition system parameters required for feasible full‐waveform inversion.

Using sonic log data to investigate a multiple problem in the Hassi R'mel field, Algeria

The conventional seismic reflection processing methods for detecting and suppressing multiples tend to fail in some circumstances. Vertical seismic profile (VSP) corridor stacks are now widely used to differentiate between primaries and multiples. However, they sometimes prove ineffective and the classical approach, using synthetics, becomes unoutlined. In the Hassi R'mel field, a strong event on the surface seismic sections, between clayey Dogger and lagoonal Dogger tops, is suspected to be a multiple because it is practically missing on the outside VSP corridor stacks. In this study, we show that the inside and outside VSP corridor stacks cannot help to identify this event. Using synthetics derived from well logs, acquired in six wells regularly distributed on the field, we conclude that the event is a primary. VSPs and sonic logs were recorded in the same well in every case. Synthetics, with multiples only, show an energetic long-path multiple with inverse polarity, at the same time as the event on the surface seismic sections. This explains: 1—the vanishing of the primary on the VSP corridor stacks, due to vertical recording in zero offset VSP acquisition, and 2—the efficiency of the standard common-midpoint (CMP) stacking to suppress the multiple on the surface seismic sections because of normal moveout differences between primaries and long-path multiples within the far-offset regions of data gathers.

Local migration with extrapolated VSP Green’s functions

We have developed a novel vertical seismic profile (VSP) imaging method that requires only a local velocity model around the well. This method is denoted as a “local migration,” where the model-based forward-propagation and backward-propagation operators are computed using a local velocity model between the well and the target body. The velocity model for the complex overburden and salt body is not needed, and the source-side statics are automatically accounted for. In addition, kinematic and dynamic effects, including anisotropy, absorption, and other unknown/undefined rock effects outside of this local velocity model, are mostly accounted for. Numerical tests on an acoustic 2D Sigsbee VSP data set, an elastic salt model, and offset 2D VSP data in the Gulf of Mexico partly validate the effectiveness of this method by accurately imaging the sediments next to the vertical well.

Seismic velocity, anisotropy, and fluid pressure in the Barbados accretionary wedge from an offset vertical seismic profile with seabed sources

The state of compaction and fluid pressure in the Barbados accretionary wedge near its toe, at Ocean Drilling Program Site 949, were investigated by modeling travel times of seismic waves from ocean bottom shots to a borehole geophone array. The model, constrained by a three‐dimensional seismic survey and well logs, shows (1) a velocity gradient of about 1–1.25 s−1 in the uppermost 180–230 m of the wedge; (2) a zone of variable, but no net change in, velocity between 230 and 350 m depth; (3) a low‐velocity zone 40–50 m thick just above the décollement at 391 m; and (4) a displacement of the low‐velocity zone by thrust faults. Pore fluid pressure sections derived from P wave velocity show that the upper half of the wedge is normally pressured while the lower half is overpressured. The ∼160 m thick, underconsolidated basal zone shows anisotropy, which increases downward. The lowest 40–50 m has velocity varying (1) azimuthally (3%), being fastest in the direction of plate convergence, and (2) in the vertical plane (2–5%), horizontal faster than vertical. After correction for the effect of anisotropy in the derivation of effective stress from seismic velocity the calculated pore fluid pressure ratio λ does not exceed 0.9 and in the lowest 40–50 m of the basal zone, is between 0.71 and 0.82, with λ* [(fluid pressure − hydrostatic)/(lithostatic pressure − hydrostatic)] between 0.5 and 0.65, in accordance with in situ measurements of fluid pressure in the décollement zone beneath. These indicate that the accretionary wedge is stronger and less overpressured than was previously supposed.

Depth imaging with multiples

Depth imaging with multiples is a prestack depth migration method that uses multiples as the signal for more accurate boundary mapping and amplitude recovery. The idea is partially related to model‐based multiple‐suppression techniques and reverse‐time depth migration. Conventional reverse‐time migration uses the two‐way wave equation for the backward wave propagation of recorded seismic traces and ray tracing or the eikonal equation for the forward traveltime computation (the excitation‐time imaging principle). Consequently, reverse‐time migration differs little from most other one‐way wave equation or ray‐tracing migration methods which expect only primary reflection events. Because it is almost impossible to attenuate multiples without degrading primaries, there has been a compelling need to devise a tool to use multiples constructively in data processing rather than attempting to destroy them. Furthermore, multiples and other nonreflecting wave types can enhance boundary imaging and amplitude recovery if a full two‐way wave equation is used for migration. The new approach solves the two‐way wave equation for both forward and backward directions of wave propagation using a finite‐difference technique. Thus, it handles all types of acoustic waves such as reflection (primary and multiples), refraction, diffraction, transmission, and any combination of these waves. During the imaging process, all these different types of wavefields collapse at the boundaries where they are generated or altered. The process goes through four main steps. First, a source function (wavelet) marches forward using the full two‐way scalar wave equation from a source location toward all directions. Second, the recorded traces in a shot gather march backward using the full two‐way scalar wave equation from all receiver points in the gather toward all directions. Third, the two forward‐ and backward‐propagated wavefields are correlated and summed for all time indices. And fourth, a Laplacian image reconstruction operator is applied to the correlated image frame. This technique can be applied to all types of seismic data: surface seismic, vertical seismic profile (VSP), crosswell seismic, vertical cable seismic, ocean‐bottom cable (OBC) seismic, etc. Because it migrates all wave types, the input data require no or minimal preprocessing (demultiple should not be done, but near‐surface or acquisition‐related problems might need to be corrected). Hence, it is only a one‐step process from the raw field gathers to a final depth image. External noise in the raw data will not correlate with the forward wavefield except for some coincidental matching; therefore, it is usually unnecessary to do signal enhancement processing before the depth imaging with multiples. The input velocity model could be acquired from various methods such as iterative focusing analysis or tomography, as in other prestack depth migration methods. The new method has been applied to data sets from a simple multiple‐generating model, the Marmousi model, and a real offset VSP. The results show accurate imaging of primaries and multiples with overall significant improvements over conventionally imaged sections.

VTI documented

Shear‐wave (S‐wave) seismic data indicate that rocks of McElroy oil field on the Central Basin Platform of West Texas are transversely isotropic with a vertical symmetry axis (VTI). Although geophysicists from time to time had anticipated or assumed that sedimentary rock was VTI, no one had shown that any sedimentary section actually was VTI. The proof at McElroy comes from a nine‐component, near‐offset vertical seismic profile (VSP) combined with a ring of 15 offset VSPs spaced about 24° apart at offsets of about 460 m. S-wave splitting at VSP frequencies was negligible for vertical propagation to a depth of 885 m but reached about 12 ms for nonvertical propagation from the offset source locations. Crossed‐dipole log data supported the VSP result for vertical propagation but found two layers of vertically birefringent rock at depth whose thicknesses were below VSP resolution.

CDP mapping and image reconstruction by using offset VSP data

Because zero-offset VSP (Vertical Seismic Profile) data can only provide the information of rock properties and structure in the area around the Fresnel zone within the well, the scheme of VSP with offset was developed to acquire the reflection information away from the borehole in order to widen the range of VSP survey and to improve the precision of imaging.

Transmission‐reflection tomography: Application to reverse VSP data

A multiphase tomographic algorithm is presented that allows 2-D and 3-D slowness (inverse of velocity) and variable reflector depth to be reconstructed simultaneously from both transmission and reflection traveltimes. We analyze the ambiguity in the determination of velocity and depth in transmission and reflection data and realize that depth perturbation is more sensitive to reflection traveltime anomalies than slowness perturbation, whereas the reverse is true of transmission traveltime anomalies. Because of the constraints on velocity and depth provided by the different wave types, this algorithm reduces the ambiguity substantially between velocity and depth prevalent in reflection tomography and also avoids the undetermined problem in transmission tomography. The linearized inversion was undertaken iteratively by decoupling velocity parameters from reflector depths. A rapid 2-D and 3-D ray‐tracing algorithm is used to compute transmission and reflection traveltimes and partial derivatives with respect to slowness and reflector depth. Both depth and velocity are parameterized in terms of cubic B‐spline functions. Synthetic examples indicate the improvement in tomographic results when both transmission and reflection times are included. The method has been applied to a reverse vertical seismic profile (VSP) data set recorded on the British coal measures along a crossed‐linear array. Traveltimes were picked automatically by the simultaneous determination of time delays and stacking weights using a waveform matching technique. The tomographic inversion of the observed reverse VSP images two fault‐zones of lower velocity than the surrounding media. The location of the faults was confirmed by near‐by reflection lines. The technique can be applied to offset VSPs or reverse VSPs and coincident VSP and surface reflection data.