Vertical Seismic Profile Surveys Research Articles

Elastic-waveform inversion and imaging of 2010 walkaway VSP data from the Raft River geothermal field

A vertical seismic profiling (VSP) survey conducted in 2010 in the original RRG-9 well at the Raft River geothermal field is to understand the subsurface geologic structures for geothermal reservoir characterization. This survey consists of 40 three-component (3C) geophones deployed in the upper 600 m of the well and 255 vibroseis sources positioned along eight walkaway lines at the surface. We perform elastic-waveform inversion and reserve-time migration of the VSP data to obtain high-resolution subsurface images. We first process the raw walkaway 3C VSP data and separate the upgoing compressional-to-compressional (PP) and compressional-to-shear (PS) wavefields. We then build an initial velocity model based on sonic logging and zero-offset VSP data, update the initial model with first-arrival traveltime tomography, and refine the model using elastic-waveform inversion to reveal high-resolution velocity variations. We finally apply reverse-time migration to the upgoing wavefields to obtain high-resolution PP and PS migration images of the lithologies encountered in the well. The refined velocity models obtained using elastic-waveform inversion improve the subsurface migration imaging results. Our elastic-waveform inversion and reverse-time migration confirm the lithology interfaces revealed from well logs and provide images of subsurface geologic layers away from well RRG-9 at the Raft River geothermal field.

Modeling and interpretation of scattered waves in interstage distributed acoustic sensing vertical seismic profiling survey

Optimization of well spacings and completions are key topics in research related to the development of unconventional reservoirs. In 2017, a vertical seismic profiling (VSP) survey using fiber-optic-based distributed acoustic sensing technology was acquired. The data include a series of VSP surveys taken before and immediately following the hydraulic fracturing of each of 78 stages. Scattered seismic waves associated with hydraulic fractures (HFs) are observed in the seismic waveforms. Kinematic traveltime analysis and full-wavefield modeling results indicate that these scattered events are converted PS-waves. We have tested three different models of fracture-induced velocity inhomogeneities that can cause scattering of seismic waves: single HF, low-velocity zone (LVZ), and tip diffractors. We compare the results with the field observations and conclude that the LVZ model has the best fit for the data. In this model, the LVZ represents a stimulated rock volume (SRV). We have developed a new approach that uses PS-waves converted by SRV to estimate the half-height of the SRV and the closure time of HFs. This active seismic source approach has the potential for cost-effective real-time monitoring of hydraulic fracturing operations, and it can provide critical constraints on the optimization of unconventional field development.

Seismic imaging of a near-vertical vein using controlled-source seismic interferometry

New methodologies for narrow-vein mining are making thin, steeply dipping mineralized veins economically viable mining targets. Drilling is the normal method for delineation and resource evaluation prior to mining. However, for the evaluation of narrow veins, significant drilling of barren rock is required. Controlled-source seismic interferometry has the potential to significantly decrease the costs of target delineation by providing high-resolution seismic images of thin, steeply dipping mineralized veins. We present a case study that employs seismic interferometry in conjunction with a walkaway vertical seismic profiling survey to image a thin (0.5–4 m), steeply dipping barite vein. The footprint of the seismic data acquisition is relatively small and compatible with operations in areas with limited access (e.g., mining camps). The technique requires some care with experimental design and data processing, but it is clearly demonstrated to produce a high-resolution seismic image. Furthermore, we demonstrate that inversion of the depth-migrated image can be used to quantify vein thickness and provide direct information for resource evaluation and reserve estimation.

Quest CCS Facility: Microseismic System Monitoring and Observations

In August 2015, CO2 injection commenced at the Quest Carbon Capture and Storage (CCS) Facility located near Fort Saskatchewan, Alberta, Canada. Quest is a fully integrated CCS facility with a capture target of just over one million metric tonnes of CO2 per year. CO2 is injected into a deep saline aquifer, the Basal Cambrian Sandstone (BCS), at a depth of about two kilometers below ground. In order to demonstrate containment and conformance of the injected CO2, a Measurement, Monitoring and Verification (MMV) plan has been implemented. Although Quest is in an extremely quiet tectonic location, induced seismicity has been recognized as a potential risk for all large-scale injection sites. As a result, microseismic monitoring is a key component of the Quest MMV Plan to ensure the continued assessment of that risk and to provide early notice of any changes. The aim of this presentation is to detail why we monitor for microseismic activity and how we do this efficiently using proactive technical monitoring (PTM) and exception based surveillance (EBS), to report on six years of microseismic monitoring observations through the pre- and post-start of injection periods and to describe the empirical analysis that has allowed the Quest CCS Facility to de-risk microseismicity as an active threat to containment. Microseismic data is continuously recorded at the Quest CCS storage site using a commercial downhole geophone array installed in a deep monitoring well (DMW). The data are processed to produce trigger files using a common algorithm for event detection and triggering, based on the ratio of short-time-average to long-time-average (STA/LTA) amplitudes. The triggered events are analyzed, classified and reported daily. Categories for various trigger types are defined based on the characteristics of each event. Operationally, the status of the microseismic array is continually assessed by the presence of trigger events. A trigger event is defined to be locatable when it shows clear primary (P) and secondary (S) wave field arrivals. The locatable events are processed and located using an anisotropic velocity model. The p-wave velocities were derived from a vertical seismic profile survey, and the s-wave velocities were obtained from sonic well logs. Pre-CO2 injection recording of microseismic data began in November 2014. Most of the trigger files generated were related to surface, automatic and noise triggers. These events were used to assess the health of the system. No locatable events were detected during the pre-injection monitoring phase. The first locatable event was recorded 10 months after start of CO2 injection in July 2016 with a magnitude of -1.3. Since January 2017, sustained low level, small magnitude microseismic activity have been located within the Quest microseismic area of review (AOR) within the Precambrian basement. The AOR as defined in the 2017 Quest MMV plan, extends 10 km radially outwards from each active injection well (IW). As of December 31st, 2020, 486 locatable events have been detected, with an average magnitude of -0.7, a maximum magnitude of 0.8 and a typical occurrence rate of 1-2 events per week. Using the current methodology, all locatable events have been located within the Precambrian basement, below the injection zone. None of this microseismic activity has represented a risk to containment.

The effect of geologic structure on fracture characterization using azimuthal vertical seismic profiles

Azimuthal vertical seismic profile (AzVSP) surveys have commonly been used for fracture characterization by analyzing the P-to-S converted wave response across fractured zones. Fractured media produce characteristic two-cycle patterns on AzVSP gathers that are disrupted in the presence of complex structures. Aiming to characterize the complexity of the AzVSP response in the presence of geologic structures, we have derived anisotropy parameters for effective horizontal transverse isotropic media, generated AzVSP signatures for the flat-interface case as the baseline, and compared the baseline signatures with AzVSP signatures for the dipping-interface cases. The fracture fill and fracture intensity are varied to capture the effect of the intrinsic fracture parameters on the AzVSP signatures. We find that dry fractures produce a stronger response compared with fluid-filled fractures for the same fracture density. The structural response on AzVSP signatures is isolated by generating synthetic seismograms across structurally equivalent isotropic models. Transverse energy, resulting from structures, could be misinterpreted as evidence for fracturing. The AzVSP signatures for a fractured dipping-interface two-layer model show significant distortion of the fracture response for the 10° dip case compared with the flat-interface signatures. As a possible solution to the structural problem, we use the arrival azimuths of the transmitted P-to-S event in synthetic signatures generated with the isotropic structural model, to orient the radial and transverse components parallel and perpendicular to the isotropic P-to-S event, respectively. Such structurally consistent orientation negates the effect of structure on AzVSP gathers and uncovers the underlying fracture response. This methodology can be extended to complex overburdens that are structurally well constrained.

Propagation of waves with a wide range of frequencies in digital core samples and dynamic strain anomaly detection: carbonate rock as a case study

SUMMARYRecent advancements in various types of seismic measurement methods, such as sonic logging, vertical seismic profiling (VSP) and surface seismic surveys, have allowed the high-quality measurement of seismic wave propagation over a broad frequency range. To elucidate the relationship between seismic wave propagation captured by various seismic methods at widely different frequencies and in highly heterogeneous zones (e.g. fractures, vuggy zones) developed in carbonate reservoirs, laboratory measurements have been conducted over a broad frequency range. However, existing laboratory methods measure the effective properties over an entire core sample. Furthermore, there are few laboratory measurements of individual fracture stiffnesses. We propose a method to indirectly estimate the local properties caused by local anomalies (e.g. fractures) in a core sample over a broad frequency range from the dynamic elastic properties of a dry core sample using synthetic seismic waveforms generated from a digital volume of the core sample. 3-D numerical simulations were conducted over a broad frequency range using a digital core model produced by X-ray computed tomography. The proposed method was applied to numerical models and two types (fractured and vuggy) of carbonate core plugs acquired in an Abu Dhabi oil field, with the frequency ranging from 200 Hz to 100 kHz in the tests. Local strain anomalies and their frequency dependencies were successfully detected in the fractured core plug. Such frequency-dependent local responses could be associated with the micromechanics of incomplete solid–solid contacts at fractures or the heterogeneity of core samples, and thus with the frequency-dependent fracture stiffness. It was also demonstrated that the heterogeneity-induced local strain in a vuggy core plug may affect the accuracy of existing low-frequency laboratory measurements.

Inverse Gaussian beam stacking method for imaging both primary reflections and free-surface multiples in 2D VSP

Abstract In vertical seismic profiling (VSP) exploration, it is difficult to produce an accurate image for large-offset reflections only using reflection waves and the image resolution is low in traditional VSP-CDP stacking as is the number of folds of reflection points. To mitigate these problems, we present an inverse Gaussian beam stacking method for imaging both primary reflections and free-surface multiples. We first compute the stacking weighted functions at each trace location by Gaussian beam forward modeling, and then apply an inverse projection for VSP data to produce common shot gathers (CRP). Since inverse Gaussian beam stacking maps the common-shot data along finite-frequency wave-paths instead of single rays as the traditional ray-based stacking method does, it enlarges the reflection-point coverage, increases stacking fold and reduces the requirement for large bin sizes. We incorporate free-surface multiples into the proposed inverse Gaussian beam stacking, which enables us to expand the horizontal imaging aperture and mitigate the low-fold problem of primary reflections in the shallow large-offset regions for VSP surveys. Numerical examples for synthetic and field data demonstrate the feasibility and adaptability of the proposed inverse Gaussian beam stacking method for VSP data.

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.

Modeling the seismic response of individual hydraulic fracturing stages observed in a time-lapse distributed acoustic sensing vertical seismic profiling survey

In 2017, distributed acoustic sensing (DAS) technology was deployed in a horizontal well to conduct a vertical seismic profiling survey before and after each of 78 hydraulic fracturing stages. From two vibroseis source locations at the surface, time shifts of P- and S-waves were observed but decayed over days. Some stages also showed waves scattered off the stimulated rock volume. We have used 2D finite difference elastic wavefield modeling to understand these observations and connect them to underlying properties of the stimulated rock. We have developed an effective medium model of vertical fractures that close exponentially with time as fluid leaks off into the formation can match the distribution of P- and S-wave time shifts along the well. This has enabled estimates of the height, normal and tangential fracture compliance values, and decay time of the stimulated rock volume. Additionally, the kinematics of scattered waves observed in the data have been found to be consistent with PS conversion across the stimulated rock volume from an individual stage. With higher quality DAS data, stage-by-stage inversion for height, fracture compliance, and decay time attributes may be possible for characterizing variations in the effectiveness of hydraulic 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.

Estimation of velocity and borehole receiver location via full waveform inversion of vertical seismic profile data

ABSTRACTBecause a vertical seismic profile (VSP) survey includes the installation of geophones into a borehole, the results of data processing are influenced by the deviation error of the borehole trajectory. In particular, when full waveform inversion (FWI) is applied to VSP data, receiver location errors distort the results of velocity inversion. Under this circumstance, we attempt to estimate the exact locations of receivers and resolve the distortion of the inverted velocity model by adding receiver locations to the inversion parameters. This makes the FWI process a multi-parametric inverse problem. In this case, it is desirable to invert each parameter group alternatively. Because receiver coordinates depend on borehole trajectory, the inverse problem is regularised by adding a term measuring the curvature of the borehole trajectory gradient to obtain a physically meaningful solution. In addition, we propose a grid search method to improve the estimation of receiver coordinates. In the case of VSP data, the inversion of receiver coordinates using the grid search method is more efficient and robust than using a local descent method. Through numerical examples, we verify that the proposed inversion algorithm can improve FWI results and mitigate velocity distortion. We also demonstrate that the convergence of FWI can be improved by applying the grid search method to the estimation of receiver coordinates.

Results of a walk‐above vertical seismic profiling survey acquired at the Thônex‐01 geothermal well (Switzerland) to delineate fractured carbonate formations for geothermal development

ABSTRACTThis paper deals with the design, acquisition and processing of vertical seismic profiling data collected in 2016 at the directional Thônex‐01 geothermal well, drilled in 1993 in the Geneva Canton (Switzerland). The aim of the study was to obtain additional information from existing‐abandoned well for downhole geophysical characterization of potential geothermal reservoirs in the Geneva area. The main results obtained by this study allowed an improved subsurface image by multi‐offset acquisitions near and around the deviated well. Specifically we were able to (1) improve the velocity model of the Geneva Basin, which, at present, is only constrained by one unique deep exploration well, located at the south‐west of the basin, far away from the study area; (2) image the transition between the Tertiary Molasse siliciclastic sediments and the Mesozoic carbonates; (3) define an acquisition strategy for future vertical seismic profiling surveys in support of the geothermal exploration campaigns in the area. This study has demonstrated the value of vertical seismic profiling method for the refinement of the subsurface geology at local scale, and its usefulness to assist the planning of second well associated with geothermal doublets.

Salt/sediment proximity to delineate salt boundaries using seismic while drilling in the Gulf of Mexico

Between July 2018 and January 2019, Shell acquired two vertical seismic profiling (VSP) surveys in two deepwater wells in the Gulf of Mexico by using a seismic while drilling (SWD) tool. Each survey included a rig source zero-offset VSP and a boat source offset VSP. The main objective of the surveys is to delineate the salt-sediment boundary at the salt base and flank. We design and execute the complex VSP surveys with emphasis on optimization, efficiency, and integration. We develop a comprehensive analysis and processing method to integrate P-wave sediment and salt proximities with converted PS salt proximity. We use SWD-VSP surveys to demonstrate how we define the salt boundary with the integrated results. Our results show that we can delineate the salt boundary with better accuracy and with a high degree of confidence. These successful VSP surveys provide significant business and technical value.

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.

Fluid prediction of a deep carbonate reservoir using walkaround 3D-3C vertical seismic profiling data

AbstractThe considerable depth and complicated structure of the Tahe Oilfield in the Tuofutai area of China make it very difficult to delineate its Ordovician carbonate fracture-cavity reservoir. The resolution of conventional ground seismic data is inadequate to satisfy current exploitation requirements. To further improve the understanding of the carbonate fracture-cavity reservoir of the Tahe Oilfield and to provide predictions of reservoir properties that are more accurate, a walkaround 3D-3C vertical seismic profiling (VSP) survey was conducted. First, we preprocessed raw VSP data and developed a method of joint PP- and PSV-wave prestack time migration. In contrast to ground seismic imaging profiles, VSP imaging profiles have a higher resolution and wider spectrum range that provide more detailed strata information. Then, using the joint PP- and PSV-wave prestack inversion method, we obtained the PP- and PSV-wave impedance and Poisson's ratio parameters of the Ordovician carbonate reservoir. Compared with the P-wave impedance of the ground seismic inversion, we found the VSP inversion results had higher accuracy, which enabled clearer identification of the internal characteristics of the carbonate reservoir. Finally, coupled with the Poisson's ratio attribute, we predicted the distribution of favorable reservoirs and interwell connectivity. The prediction results were verified using both logging and production data. The findings of this study demonstrate the applicability of the proposed technical method for the exploration of deep carbonate fracture-cavity reservoirs.

Reverse time migration of transmitted wavefields for salt boundary imaging

The imaging of steep salt boundaries has received much attention with the advent of improved wider azimuth acquisition designs and advanced imaging techniques such as reverse time migration (RTM), for example. However, despite these advancements in capability, there are cases in which the salt boundary is either poorly illuminated or completely absent in the migrated image. To provide a solution to this problem, we have developed two RTM methods for imaging salt boundaries, which use transmitted wavefields. In the first technique, downgoing waves, typically recorded in walkaway vertical seismic profile surveys, are used to image the salt flank via the generation of aplanatic isochrones. This image can be generated in the absence of an explicit interpretation of the salt flank using dual migration velocity models, as demonstrated on a 3D walkaway field data set from the Gulf of Mexico. In the second technique, we extend the basic theory to include imaging of upgoing source wavefields, which are transmitted at the base salt from below, as acquired by a surface acquisition geometry. This technique has similarities to the prism-imaging method, yet it uses transmitted instead of reflected waves at the salt boundary. Downgoing and upgoing methods are shown to satisfactorily generate an image of the salt flank; however, transmission imaging can create artifacts if reflection arrivals are included in the migration or the acquisition geometry is limited in extent. Increased wavelet stretch is also observed due to the higher transmission coefficient. An important benefit of these methods is that transmission imaging produces an opposite depth shift to errors in the velocity model compared with imaging of reflections. When combined with conventional seismic reflection surveys, this behavior can be used to provide a constraint on the accuracy of the salt and/or subsalt velocities.

Land VSP seismic sources evaluation: CO2CRC Otway project case study

It is widely accepted that, depending on acquisition technique, vertical seismic profiling (VSP) can provide us with extremely valuable information on seismic velocities (both P and S), attenuation and anisotropy of s eismic properties of the earth. Subsurface images, obtained with offset or 3D VSP could demonstrate superior resolution, signal-to-noise ratio and repeatability of surveys in comparison to standard surface seismic. These potential benefits are of great importance for both reservoir characterisation and time-lapse seismic monitoring. However in order to achieve them VSP surveys should be acquired with proper survey design and optimal source and receiver characteristics.

A new system surveys for efficiently acquiring vertical seismic profile

A vertical seismic profile (VSP) survey involves placing sensors in a borehole to record the passage of energy transmitted using a source of seismic energy placed on the surface. The sensors are usually contained within sondes that are coupled to the borehole wall using mechanical clamps. Existing VSP acquisition systems are generally unsuitable for acquisition using the wireline units typically used for minerals logging. In this paper we describe a new multis-sonde VSP acquisition system specifically designed for acquiring high-resolution VSP surveys in hard-rock environments.

Time-lapse seismic monitoring of individual hydraulic frac stages using a downhole DAS array

A fiber-optic distributed acoustic sensing system (DAS) was recently installed in an Apache-operated horizontal shale well and used to acquire downhole seismic data before, during, and after the well was treated in order to better understand the time-lapse seismic response to hydraulically stimulated fractures. In addition to a 3D/4D DAS vertical seismic profiling survey acquired before and after the well was treated, data were recorded from two fixed shot locations approximately 1 mile off each end of the lateral part of the well. These shots were repeated after each of the 78 frac stages used to treat the well in an attempt to achieve more continuous seismic monitoring of the hydraulic-stimulation process. Despite the noisy environment associated with ongoing frac operations, these data proved to be valuable in understanding the fundamental seismic response to each frac stage. The dominant time-lapse effect observed in the stage-by-stage data was a subtle time delay of the P-wave direct arrival when compared to data recorded prior to stimulation. This time-lapse effect was only present over a period of a few days once the stage was completed and would have been completely missed using the conventional approach of having a single monitor survey acquired after the well was treated. It was possible to model the kinematics of the P- and S-wave arrivals and invert for frac effectiveness at each stage based on the observed time delay in the seismic. Amplitude differences were also observed in the time-lapse shot records in which new waveforms appeared along the hydraulically stimulated portions of the well.