Corridor Stack Research Articles

Application of distributed acoustic sensing technology in deep shale gas exploration

Abstract In the past decade, the exploration and development of deep shale gas usually adopted geophone acquisition for vertical seismic profile (VSP) to improve the accuracy and resolution of seismic data. However, it’s very hard to use the 10-20m level spacing geophones to meet the resolution of 2-5m thin reservoir. Distributed acoustic sensing (DAS) technology has been widely used in the oil and gas field due to its advantages of high density and high efficiency acquisition, especially in vertical seismic profile and dynamic monitoring. We have acquired zero offset VSP by DAS and geophone for the first time in deep shale gas wells at home, and successfully overcome the coupling problem in open-hole sections. Vibrators are used as sources for multiple stacking to improve the signal-to-noise ratio (SNR) of DAS VSP. The records show DAS has significant advantages in frequency, SNR and wavelet consistency. After data processing, the layer velocity characteristics of DAS VSP are more obvious. DAS VSP corridor stack has a high degree of consistency with the synthetic record and seismic profile, and the resolution of the reservoir was higher than geophone.

Depth calibration of distributed acoustic sensing data using well log ties

The use of distributed acoustic sensing (DAS) to acquire vertical seismic profiles (VSPs) is becoming increasingly popular as the use of the fibre-optic cable as the sensor enables the full depth of the well to be acquired simultaneously. A major drawback in the use of DAS is tying the distance along the cable to its position within the well. In this paper, we show how the cable position can be determined over its full length using a dynamic time-warping algorithm applied to a corridor stack and synthetic seismogram. To constrain the result to ensure that result is physically realistic, we employ a constant warping window and/or a newly introduced bunching window.

Walkaway Vertical Seismic Profiling (WVSP) Modeling and Imaging Study along FaultedCoal Seams over a High Velocity Limestone Model: A Synthetic Study

The problem of collecting reflection data from the layers below a high velocity layer (HVL) and imaging those layers accurately is solved using walkaway vertical seismic profiling (WVSP) technique. The procedure is shown on a dataset from a model of highly faulted, thin-bedded coal layers separated by a high velocity layer of limestone. By locating the receivers above, in, and below the HVL, the reflections are expected to be recorded locally in situ in the borehole below the HVL before they travel back to the surface as in the case of surface seismic. The imaging results obtained from the model (or synthetic) WVSP data lead to the conclusion that promising results may be obtained via the acquisition of field WVSP data such that the layers below the HVL are well-imaged. Analysis of the test results showed that the layers below the HVL can be imaged accurately and robustly when the receivers are situated below the HVL only, while the strong images below the HVL tend to fade away and lose their strength when the receivers are moved above the HVL. However, both these cases of the receiver location geometry are needed to obtain images that are vertically and horizontally stable. When a full instrumentation of the borehole is provided, good images as far as 500 m away from the VSP borehole are obtained from the layers with various dips and faults that are nearly 800 m in depth from the surface. Two cases of velocities (4000 m/s and 5000 m/s) are tested for the high velocity limestone layer. Both cases showed good images below the HVL. Unfortunately, some pulled-up effects are seen in the images right below the HVL where the layers that are immediately below the HVL are imaged above their correct locations, the pulled-up effects are corrected in the deeper sections below the HVL however. Comparison of a depth converted corridor stack from the zero offset VSP data and the depth migrated image show good agreement.

Walkaway Vertical Seismic Profiling (WVSP) Modeling and Imaging Study along FaultedCoal Seams over a High Velocity Limestone Model: A Synthetic Study

The problem of collecting reflection data from the layers below a high velocity layer (HVL) and imaging those layers accurately is solved using walkaway vertical seismic profiling (WVSP) technique. The procedure is shown on a dataset from a model of highly faulted, thin-bedded coal layers separated by a high velocity layer of limestone. By locating the receivers above, in, and below the HVL, the reflections are expected to be recorded locally in situ in the borehole below the HVL before they travel back to the surface as in the case of surface seismic. The imaging results obtained from the model (or synthetic) WVSP data lead to the conclusion that promising results may be obtained via the acquisition of field WVSP data such that the layers below the HVL are well-imaged. Analysis of the test results showed that the layers below the HVL can be imaged accurately and robustly when the receivers are situated below the HVL only, while the strong images below the HVL tend to fade away and lose their strength when the receivers are moved above the HVL. However, both these cases of the receiver location geometry are needed to obtain images that are vertically and horizontally stable. When a full instrumentation of the borehole is provided, good images as far as 500 m away from the VSP borehole are obtained from the layers with various dips and faults that are nearly 800 m in depth from the surface. Two cases of velocities (4000 m/s and 5000 m/s) are tested for the high velocity limestone layer. Both cases showed good images below the HVL. Unfortunately, some pulled-up effects are seen in the images right below the HVL where the layers that are immediately below the HVL are imaged above their correct locations, the pulled-up effects are corrected in the deeper sections below the HVL however. Comparison of a depth converted corridor stack from the zero offset VSP data and the depth migrated image show good agreement.

Integration of VSP in the process of surface seismic data inversion

The measurements of vertical seismic profiles (VSP) used in the petroleum industry are often limited to direct arrivals to establish time-depth laws. Many other measurements such as PP and PS corridor stacks, offset vertical seismic profiles (OVSP) and walkaway can help to predict P and S wave impedances estimated by inversion of surface seismic data. This article shows the use of all available VSP records to constrain the inversion of surface seismic data and predict matrix properties of Carboniferous and Devonian intervals in the Machukhske gas field in the Ukrainian Dnieper-Donetsk basin. The use of PS corridor stack, in addition to PP corridor stack, allows a better optimization of the S impedance at the well. Moreover, corridor stacks allow a better estimate of the P and S impedance below the well TD than surface seismic data alone, and therefore an enhanced characterization of the Devonian sands, which has been drilled by only a few wells. OVSPs help to build a more reliable a priori model by confirming or discarding the faults identified on the 3D seismic data. Results of reservoir characterization show a clear impact of the VSP integration on lithology prediction from surface seismic data.

Wireline distributed acoustic sensing allows 4.2 km deep vertical seismic profiling of the Rotliegend 150 °C geothermal reservoir in the North German Basin

Abstract. We performed so-far-unprecedented deep wireline vertical seismic profiling at the Groß Schönebeck site with the novel method of distributed acoustic sensing (DAS) to gain more detailed information on the structural setting and geometry of the geothermal reservoir, which is comprised of volcanic rocks and sediments of Lower Permian age. During the survey of 4 d only, we acquired data for 61 source positions using hybrid wireline fiber-optic sensor cables deployed in two 4.3 km deep, already existing wells. While most of the recorded data have a very good signal-to-noise ratio, individual sections of the profiles are affected by characteristic coherent noise patterns. This ringing noise results from incomplete coupling of the sensor cable to the borehole wall, and it can be suppressed to a large extent using suitable filtering methods. After conversion to strain rate, the DAS data exhibit a high similarity to the vertical component data of a conventional borehole geophone. We derived accurate time–depth relationships, interval velocities, and corridor stacks from the recorded data. Based on integration with other well data and geological information, we show that the top of a porous and permeable sandstone interval of the geothermal reservoir can be identified by a positive reflection event. Overall, the sequence of reflection events shows a different character for both wells explained by lateral changes in lithology. The top of the volcanic rocks has a somewhat different seismic response in both wells, and no clear reflection event is obvious at the postulated base of the volcanic rocks, so that their thickness cannot be inferred from individual reflection events in the seismic data alone. The DAS method enabled measurements at elevated temperatures up to 150 ∘C over extended periods and led to significant time and cost savings compared to deployment of a conventional borehole geophone string. This wireline approach finally suggests significant implications for observation options in old wells for a variety of purposes.

Seismic-while-drilling applications from the first DrillCAM trial with wireless geophones and instrumented top drive

Advanced geophysical sensing while drilling is being driven by trends to automate and optimize drilling and the desire to better characterize complex near surface and overburden in desert environments. We introduce the DrillCAM system, which combines a set of geophysical techniques from seismic while drilling (SWD), drill-string vibration health, estimation of formation properties at the bit, and imaging ahead of and around the bit. We present data acquisition, processing, and initial application results from the first field trial on an onshore well in a desert environment. In this study, we focus on SWD applications. For the first time, wireless geophones installed around a rig were used to acquire continuous data while drilling. We demonstrate the feasibility of such a system to provide flexible acquisition geometries that are easily expandable with increasing bit depth without interference from drilling operations. Using a top-drive sensor as a pilot, we transform the drill-bit noise into meaningful and reliable seismic signals. The data were used to retrieve a check shot while drilling, make kinematic look-ahead predictions, and obtain a vertical seismic profiling corridor stack matching surface seismic. Robust near-offset check-shot signals were received from roller-cone and polycrystalline diamond compact (PDC) bits above 7200 ft after limited preprocessing of challenging single-sensor data with supergrouping. Detecting signals from deeper sections drilled with PDC bits may require more advanced processing by using an entire 2D spread of wireless geophones and downhole pilots. The real-time capabilities of the system make the data available for continuous data processing and interpretation that will facilitate drilling automation and improve real-time decision making.

Look‐ahead vertical seismic profiling inversion approach for density and compressional wave velocity in Bayesian framework

ABSTRACTTo reduce drilling uncertainties, zero‐offset vertical seismic profiles can be inverted to quantify acoustic properties ahead of the bit. In this work, we propose an approach to invert vertical seismic profile corridor stacks in Bayesian framework for look‐ahead prediction. The implemented approach helps to successfully predict density and compressional wave velocity using prior knowledge from drilled interval. Hence, this information can be used to monitor reservoir depth as well as quantifying high‐pressure zones, which enables taking the correct decision during drilling. The inversion algorithm uses Gauss–Newton as an optimization tool, which requires the calculation of the sensitivity matrix of trace samples with respect to model parameters. Gauss–Newton has quadratic rate of convergence, which can speed up the inversion process. Moreover, geo‐statistical analysis has been used to efficiently utilize prior information supplied to the inversion process. The algorithm has been tested on synthetic and field cases. For the field case, a zero‐offset vertical seismic profile data taken from an offshore well were used as input to the inversion algorithm. Well logs acquired after drilling the prediction section was used to validate the inversion results. The results from the synthetic case applications were encouraging to accurately predict compressional wave velocity and density from just a constant prior model. The field case application shows the strength of our proposed approach in inverting vertical seismic profile data to obtain density and compressional wave velocity ahead of a bit with reasonable accuracy. Unlike the commonly used vertical seismic profile inversion approach for acoustic impedance using simple error to represent the prior covariance matrix, this work shows the importance of inverting for both density and compressional wave velocity using geo‐statistical knowledge of density and compressional wave velocity from the drilled section to quantify the prior covariance matrix required during Bayesian inversion.

Multi-Ricker Spectral Modeling in the S-transform Domain for Enhancing Vertical Resolution of Seismic Reflection Data

DOI: 10.17014/ijog.6.3.223-233We present a relatively straightforward methodology for extending seismic bandwidth and hence enhancing the seismic resolution by performing time-variant deconvolution. We use the generalized S-transform (GST) approach in order to properly compute the time-frequency components of the seismic reflection trace. In estimating the time-variant wavelet, we propose a spectral modeling method named multi-Ricker spectral approximation (MRA). After obtaining the estimated wavelet spectrum at each time sample, a deconvolution filter can then be built and applied in the S-transform domain. This proposed time-variant seismic enhancement method needs neither information on subsurface attenuation model nor assumption that the subsurface reflectivity is random. It is a data-driven methodology which is based on the seismic data only. We validate this proposed method on a synthetic and apply to a field data. Results show that, after enhancement, overall seismic bandwidth can be extended resulting in higher vertical resolution. Correlation with VSP corridor stack at well location ensures that the generated reflection details after enhancement is geologically plausible.

Multi-Ricker Spectral Modeling in the S-transform Domain for Enhancing Vertical Resolution of Seismic Reflection Data

DOI: 10.17014/ijog.6.3.223-233 We present a relatively straightforward methodology for extending seismic bandwidth and hence enhancing the seismic resolution by performing time-variant deconvolution. We use the generalized S-transform (GST) approach in order to properly compute the time-frequency components of the seismic reflection trace. In estimating the time-variant wavelet, we propose a spectral modeling method named multi-Ricker spectral approximation (MRA). After obtaining the estimated wavelet spectrum at each time sample, a deconvolution filter can then be built and applied in the S-transform domain. This proposed time-variant seismic enhancement method needs neither information on subsurface attenuation model nor assumption that the subsurface reflectivity is random. It is a data-driven methodology which is based on the seismic data only. We validate this proposed method on a synthetic and apply to a field data. Results show that, after enhancement, overall seismic bandwidth can be extended resulting in higher vertical resolution. Correlation with VSP corridor stack at well location ensures that the generated reflection details after enhancement is geologically plausible.

3D Vertical Seismic Profiling Acquired Using Fibre-Optic Sensing Das – Results From The CO2CRC Otway Project

Distributed Acoustic Sensing (DAS) is an optical interferometric method for acquisition of acoustic and seismic signals. It uses laser pulses that travel along the length of a fibre-optic cable and backscatter as they encounter small inconsistencies in the fibre. Impinging seismic waves cause strain on the cable, resulting in differences in phase of the backscattered light. Interest in DAS has increased significantly in the past decade as it is particularly suited for VSP acquisitions, including for permanent reservoir monitoring. Fibre-optic cables can be installed permanently in the well, cemented behind the casing or attached to tubing; they offer a relatively cheaper and efficient solution when compared to conventional borehole sensors. This study is part of the CO2CRC Otway Project. The Otway Project site is located approximately 240 km south-west of Melbourne, Australia. The Stage 2C of the project aims to monitor a small injection (15 kt) of CO2/CH4 gas mixture at a depth of approximately 1500 m. Here, we show the results of a 3D VSP survey acquired using DAS cable deployed on production tubing in the injector well. The DAS up-going wavefield shows a high level of noise. However, DAS is able to record the main reflections, including at the injection depth. After 3D migration of the data, noise levels reduce significantly. Events on DAS inline match with events on a corridor stack produced from a geophone check-shot data. Due to the directionality pattern, DAS was only able to image up to approximately 300 m radius from the well.

Characterization and imaging of a hydrothermally active near-vertical fault zone in crystalline rocks based on hydrophone VSP data

A shallow, hydrothermally active, fault zone embedded in fractured crystalline rocks of the Central Swiss Alps has been drilled and geophysically explored in view of its potential analogies to planned petrothermal reservoirs in the Alpine Foreland. Vertical seismic profiling (VSP) experiments have been performed using a 24-channel borehole hydrophone array with a sensor spacing of 1 m in order to image the fault core and to detect hydraulically open fractures. The dense sensor spacing allows for an accurate sampling of the wavefields. This, in turn, enables their separation through standard seismic processing methodologies, thus allowing for the generation of seismic body wave VSP profiles and a tube wave corridor stack, which maps brittle deformation in the surrounding rock mass.Multiple offset hydrophone VSP data were acquired with a crooked-line survey geometry and processed with 3D methods. Hereby, a laterally changing velocity cube, representative of the vertical structural variations associated with the fault zone, is generated and utilized for Kirchhoff pre-stack-depth-migration (PSDM) imaging. The resulting seismic image delineates various vertical structures, notably the target fault zone. The interpretation of the VSP data is complemented by and corroborated through a suite of geophysical borehole logs, which characterize the fine-scale petrophysical variations in response to brittle deformation in the fault core and the surrounding damage zones.This study exemplifies typical targets of hardrock seismic exploration, where the structures are frequently near-vertical, discontinuous and where acoustic impedance contrasts are commonly associated with deformation. As such, it illustrates the benefits of using borehole seismic methods in such environments and the use of borehole hydrophone arrays for targeting fractures and shear zones.

Imaging the high-temperature geothermal field at Krafla using vertical seismic profiling

Geophysical exploration and in particular active-source seismic imaging of geothermal fields is important to assess and optimize the exploitation of natural heat sources for energy production and direct use. The first multi-offset (moving-source) vertical seismic profiling (VSP) experiment over the high-temperature geothermal field in Krafla (Iceland) was carried out in spring 2014 with the aim to test whether VSP is a suitable method to map volcanic stratigraphy, fractures, dykes, steam zones and magmatic bodies at this site and for volcanic environments in general. In this study, we present a workflow for processing the sparse Krafla VSP dataset recorded with receivers in either of two boreholes. The analysis involved first-arrival traveltime inversion and seismic reflection processing. The seismic velocity model obtained by traveltime tomography reveals structural information between the two boreholes and can be linked to an existing geological model, showing that the seismic velocities are mainly controlled by lithology. The zero-offset seismic reflection data were processed into two corridor stacks. Walk-away VSP reflection data were migrated with a novel multicomponent Kirchhoff migration algorithm that includes P- and S-wave isolation to obtain separate PP, PS and SS migrated images. The reflections imaged in the corridor stacks can be linked to the main lithological units known from borehole logging information. Migrated images from the walk-away data reveal reflectors below and to the sides of the two boreholes. Considering à priori information, such as hypocenter locations from earthquake seismology studies, the reflectors can be related to changes in lithology, fault zones, dykes and possibly the top of the Krafla magma chamber. We found that VSP is potentially a useful method to image the key lithological boundaries and volcanic stratigraphy in the complex magmatic environment at Krafla, but à priori information proved to be essential to constrain the processing and interpretation of the sparse array dataset.

Enhancement of Seismic reflectors by using VSP and Seismic Inversion in Sindbad oil field, south of Iraq

The purpose of this research is to enhance the methods of surface seismic data processing and interpretation operations by using the produced information of vertical seismic profile (measured velocity and corridor stack). Sindbad oil field (South of Iraq) is chosen to study goals and it's containing only one well with VSP survey (Snd2) that covering depth from Zubair to Sulaiy Formations and 2D seismic lines of Basrah Survey. The horizons were picked and used with low frequency contents from well data for the construction of low frequency model and it was used with high frequency of VSP to make the high frequency model that compensated to seismic main frequency through inversion process. Seismic inversion technique is performed on post stack of 2D seismic data (2Br2) through Hampson-Russell CGG program. The inversion model of low frequency shows 88.5% matching with relative seismic impedance while high frequency model 93.3% matching with lower error percent. The two impedance sections which resulted from inversion model were convoluted with best wavelet from VSP data to make a new seismic section. The LFM section was similar to original seismic section while the HFM section shows real enhancement of the Flatspot (DHI) feature and recoverable some missing reflectors.

Model-based interbed multiple attenuation: a case study of Najmah reservoir, North Kuwait Jurassic

The Late Jurassic Najmah Formation of Northeast Kuwait consists of a fractured tight carbonate reservoir and organic-rich kerogen layer (Figure 1). Development of the Najmah reservoir is contingent on recognizing naturally fractured areas. Prior to seismic reservoir characterization, it is essential to ensure that the data quality is reliable before extracting any information from the seismic data. Noise contamination can obscure the reflections of interest, leading to inaccurate interpretation and the need for further data analysis for reservoir delineation. Data acquired in the study area indicates that P-wave seismic data within the reservoir interval suffers from the interference of coherent noise related to the interbed multiple. The interbed multiple is a serious problem that is common in the land seismic datasets in the Middle East (Al-Khaled et al., 2008; Al-Nahhas et al., 2008; El-Emam et al., 2011, 2005; Lesnikov and Owusu, 2011; Ras et al., 2012; Sonika et al., 2012; Wu et al. 2011). This study utilized a 9 mile2 (23.3 km2) 3D full azimuth P-wave seismic data set provided by Kuwait Oil Company (KOC) to the Reservoir Characterization Project (RCP) at the Colorado School of Mines. The seismic data was a preliminary result of pre-stack time migration from continuing seismic data processing. Short and long period demultiple and interbed demultiples were applied during the original data processing. A synthetic seismogram of well B portrays the reservoir interval with greater amplitude than the seismic data (Figure 2). This anomaly is consistently observed for all seismic well ties of ten available wells within the 3D seismic data. Furthermore, inside-outside corridor stack analysis of zero-offset VSP (Vertical Seismic Profile) depicts similar amplitude difference that indicates the presence of noise interference from multipathing of seismic energy above the reservoir interval. Evidence of the presence of multiples can be observed from the raw stack of down-going wavefields of the zero-offset VSP. Interbed multiple effects on the seismic data can be seen as a periodic repetition of reflection events, either individual events or interference with primaries. In this case, the multiples seem to interfere with the primary reflection. This study reveals interbed multiples related to the first anhydrite layer within the Gotnia Formation above the reservoir layers are the primary cause of the interference. Applying model-based interbed multiple attenuation reduces the noise interference and improves the imaging of the reservoir section. The multiple-attenuated seismic data have a better correlation with synthetics derived from ten control wells used in this study, leading to better seismic inversion accuracy and reservoir characterization.

Seismic imaging in the Krafla high-temperature geothermal field, NE Iceland, using zero- and far-offset vertical seismic profiling (VSP) data

Among geothermal exploration methods, active surface seismic methods have played only a minor role to date. Especially in high-temperature volcanic systems, reflection seismic data often reveal poor delineation of volcanic features, due to the internal heterogeneity of volcanic sequences. To enhance the vertical resolution, one possibility is the application of downhole seismic methods like vertical seismic profiling (VSP). A test experiment was carried out in the Krafla high-temperature geothermal field, NE-Iceland, to assess the ability of VSP to image subsurface structures, such as fractures, zones of high permeability, magmatic bodies, and zones of supercritical fluids and steam. Logging in such hostile environments is technical challenging in many aspects, but mainly due to the high temperature impact on the downhole electronic components of the measuring equipment. This requires a thorough pre-examination and implementation of the measurement, especially to avoid delays and tool failures. This paper presents results of zero- and far-offset VSP data from the K-18 borehole from within the Krafla caldera, which reveal good correlation with the surrounding lithology. The raw three-component seismic data display a good signal-to-noise ratio and dominant signal frequencies between 20 and 40 Hz, down to c. 2200 m depth, for air gun and explosive sources, respectively. A zero-offset source comparison was also conducted to assess the use of different impulsive sources for future VSP surveys in similar settings. By applying a standard VSP processing, we identified stratigraphic boundaries between lavas, hyaloclastites, and intrusions, which are in good agreement with existing well data. For the zero-offset VSP, both P- and S-wave velocity models were calculated and a depth-converted corridor stack was determined. In addition, multicomponent Kirchhoff depth migration and Fresnel volume migration were tested around the borehole. The 3D results are promising, but the specific shape and lateral extent of the reflectors could not be determined due to the restriction to only two sources and the insufficient spatial coverage (aperture). Our study demonstrates that vertical seismic profiles can clearly detect variations in the subsurface volcanic stratigraphy in high-temperature geothermal fields. A more detailed reservoir characterization can be achieved by further data integration, enhanced survey design including more source positions, and improved processing and imaging techniques, such as full-waveform inversion.

Compressional- and shear-wave studies of distributed acoustic sensing acquired vertical seismic profile data

Understanding the strengths and limitations of rapidly advancing distributed acoustic sensing (DAS) technology used for recording vertical seismic profile (VSP) data is achieved by comparing DAS and geophone data sets using both compressional-wave (P-wave) and shear-wave (S-wave) VSP data and their corresponding geophysical answer products. We validate the kinematics (time) and dynamics (amplitude) of DAS VSP data by examining the extracted slowness values, response-to-incident angles, corridor stacks, and common-depth-point (CDP) transforms. For kinematics validation, the slowness values computed from P- and S-wave components of DAS VSP data agree with the geophone slowness values. For dynamics validation, we confirm the cos2 θ response of the fiber to the incident angle of the seismic wavefield for P-waves and sin 2θ for S-waves. The amplitudes of the P-wave corridor stacks are comparable; the S-wave corridor stacks are similar for shallow events and differ for later events due to the limited response of the fiber to S-waves at near-vertical angles of incidence. High-quality CDP transform images are obtained for P- and S-waves. These analyses indicate that properly acquired DAS VSP data sets are reliable for the kinetics and dynamics of both P- and S-waves. Once the fiber-optic cable is installed in the well, VSP acquisition costs are greatly reduced because DAS data may be acquired with no additional well intervention. The extensive spatial coverage obtained using fiber-optic cables, the ease of acquiring time-lapse (4D) VSP data, and the reliability of the resulting DAS VSP data sets are making DAS technology an extremely important VSP acquisition tool.

Quantitative quality of distributed acoustic sensing vertical seismic profile data

Great advances have been made in distributed acoustic sensing (DAS) vertical seismic profile (VSP) data acquisition hardware and software. Here, we capture a quantitative assessment of the quality of DAS data at a single point in time. We apply comprehensive testing methods to determine the reliability of the data and its suitability as a supplement to geophone data or to gain access to wells where it would be difficult to deploy geophones. The test measurements are made on DAS and geophone data, which were collected at the same time and in the same well. We analyze the first breaks for waveform consistency, signal-to-noise (S/N) ratio, and slowness. Then, we examine the corridor stacks for waveform consistency and S/N ratio. Finally, we test the properties of the measurement, including linearity, repeatability, reliability, and response, as a function of the angle of incidence of a seismic wave to the fiber. The results show that the DAS VSP data provide accurate formation slowness logs and reliable amplitude information suitable for creating seismic images and corridor stacks.

Initial seismic observations from a deep borehole drilled into the Canadian Shield in northeast Alberta

The availability of a deep borehole in northeastern Alberta provides an unprecedented opportunity to study the in situ metamorphic craton rocks. This borehole reaches a depth of 2.4 km, with 1.8 km in the crystalline rocks, and is the only known borehole allowing access into the deeper rocks of the metamorphic Canadian Shield. In 2011, a zero-offset vertical seismic profile (VSP) was acquired to assist in the interpretation of seismic reflection data and geophysical logs. Three sets of upgoing tube waves interpreted from the raw profile correspond to the small-scale fluctuations in the borehole diameters and fracture zone in the crystalline rocks. A comparison between sonic log velocities and VSP velocities reveals a zone with increased velocity that could be due to the change in rock composition and texture in the basement rocks. The final processed profile is used to generate corridor stacks for differentiating between primary reflections and multiples in the seismic reflection profile. Analysis of the zero-offset VSP verifies existing log interpretation on the presence of fractures and the possible lithological changes in the metamorphic rocks of the Canadian Shield.

Vertical seismic optical profiling on wireline logging cable

ABSTRACTVertical seismic profiles are usually acquired by deploying downhole seismic sensors below a wireline logging cable. A seismic source is triggered at surface while recording the downhole vibration via the wireline cable. In this paper, an alternative approach based on distributed vibration measurement is tested using wireline deployment for the first time.Local axial strain of a multi‐kilometre fibre optic line is measured at intervals of approximately 1 m and processed to a spatial resolution of 10 m with sub nanometer strain resolution by an optical interrogation device (distributed vibration/acoustic sensing). When deployed in a well, the optical fibre line should be mechanically coupled to the borehole wall to generate valid seismic records.A conventional vertical seismic profile was acquired with three‐component sensors in a vertical well near Bottesford, UK. The impulsive seismic source was a novel portable airgun tank. Clear seismic reflections are observed within and below the borehole, in agreement with surface seismic data. A single shot generated equivalent data with an experimental optical wireline logging cable and an adequate optical interrogator at the surface. The main difference between the two records is the presence of a strong tube wave in the optical profile, which can be easily removed with conventional velocity filter processing. Corridor stacks from both conventional and optical profiles match each other and provide a reasonable tie to a nearby surface seismic line.