- Home
- Conferences
- Conference Proceedings
- Conferences
3rd EAGE Workshop on Borehole Geophysics
- Conference date: 19 Apr 2015 - 22 Apr 2015
- Location: Athens, Greece
- ISBN: 978-94-6282-144-6
- Published: 19 April 2015
40 results
-
-
Fibre Optic Based Vibration Sensing: Nature of the Measurement
Authors T. Dean, A. Hartog, B. Papp and B. FrignetWithin the industry there appears to be some confusion about what fibre optic based seismic systems are actually measuring. Using synthetic and real data we show that such systems measure instantaneous strain, which is equivalent to the sum of the perturbations of each section of the gauge length from its mean position divided by its length. The time derivative of strain, the strain rate, is proportional to the average velocity measured at all points along the gauge length. DVS measurements have the polarity of a hydrophone measurement but the directionality is highly complex and depends on wavenumber as well as the angle of incidence.
-
-
-
Multi-Fibre DAS Walk-Away VSP at Kapuni
Authors P. Zwartjes and A. MateevaAs part of a field appraisal campaign in New Zealand, a set of walk-away VSP-s was acquired. That included a state-of-the-art geophone acquisition in two wells and a simultaneous multi-fibre DAS VSP in one of those wells. All VSP data were of excellent quality and provided high-resolution images. The DAS data exceeded expectations in terms of quality and resolution, aided by simultaneous acquisition on 5 fibres in the same cable. Here we discuss in more detail the benefits and complications of a multi-fibre DAS acquisition. The main benefit is that the signal-to-noise ratio of DAS can be improved without extra source effort, and at negligible extra cost for fibre installation. In addition, the multi-fibre acquisition provides opportunity for DAS channel depth QC and refinement. The main drawback is the cost of employing additional DAS interrogators for the extra fibres, as in this case the fibres were not looped in the cable.
-
-
-
Acquisition of Borehole Seismic Data in a Challenging Transition Zone
Authors T. Human and H. FernandyThis paper presents a case study of borehole seismic data acquisition in a horizontal well with source positions in a transition zone that ranges from marine to mangrove to tidal mud plain environments. Deploying geophone tools for acquiring data in horizontal wells is not new to the industry but there are still challenges to overcome. In addition, deploying multiple and repeatable seismic sources in a transition zone that can be fired in the order of 600 times take special design, planning, and execution. In this paper, we will show how the survey was designed and the source points selected. We will further show a unique method used for deploying airguns and operating them in a safe and repeatable manner. Lastly, the paper will discuss the acquisition methods that were followed.
-
-
-
Validaing a Borehole Seismic Survey in Complex Geology
Authors J. Taylor, T. Jones, C. Allen, D. Griffin, A. Campbell, E. Ferguson, J. Huff and M. MahnkeA rig-source VSP was acquired in the Gulf of Mexico (GOM) using both seismicVISION While Drilling (SVWD) and wireline VSP measurements. After a bit run, a time mistie was noted on the SVWD data. Strong ocean currents caused the rig to rotate during the bit run. After the well was complete, a wireline VSP was recorded. The rig rotated during the wireline acquisition. The same time mistie was observed. 3D ray-trace modeling was used to confirm that the strongly dipping salt structure caused a large time mistie for a very small change in source position. The possibility of rig-rotation needs to be accounted for in pre-survey design even for rig-source VSPs.
-
-
-
Integration of Multi-scale, Multi-domain Datasets to Enhance Microseismic Data Processing and Evaluation
Authors J. Le Calvez, B. Marion, L. Hogarth, C. Kolb, S. Hanson-Hedgecock, M. Puckett and B. BryansRigorous processing of microseismic data is essential and indispensable to derive confidently mapped hypocentral locations, as well as associated event attributes and source parameters. Integration with other borehole-based geophysical measurements is key in interpreting formation behavior and properties. In this study, we present the results of a microseismic monitoring campaign performed on multi-stage hydraulic fracturing treatments using two nearby, pseudo-vertical monitoring arrays composed of eight 3-component geophones each. We benefit from several borehole-based geophysical measurements, such as sonic logs, crosswell tomographic and attenuation profiles, and multi-calibration perforation points. Although, all these measurements take place in different frequency domains, together they very efficiently document the variations in space and time of the velocities, anisotropies, attenuations, and rock physics in the zones of interest and surrounding formations. Improved formation evaluation and interpretation during microseismic monitoring allows for improved estimation of reservoir quality and production in hydraulic fracturing treatments and could potentially prove useful in optimizing stage-by-stage stimulation volumes.
-
-
-
Estimating Anisotropy Using Down-Hole Microseismic Event Gathers
Authors M. Karrenbach, S. Cole and V. YartsevHydraulic fracture operations can be optimized using knowledge about the stress regime, flow permeability, and fracture networks in the subsurface. Surface seismic data and nearby well data give a first assessment of the properties present near and inside the hydraulic fracture treatment zone. However, surface seismic data produces regional or field wide estimates on a coarse scale, while well logs or sonic scanner logs provide laterally sparse, yet very detailed vertical resolution. The two measurement types provide inherently different scale lengths, leaving a resolution gap in the treatment zone. In this paper we use layer averaging from equivalent medium theory to derive coarse-scale anisotropy parameters from fine-scale log measurements in order to reconcile anisotropy estimations from microseismic event wave fields.
-
-
-
Microseismic Data Analysis, Interpretation Compared with Geomechanical Modelling
By R.J. ZinnoMicroseismic monitoring data has initiated many paradigm changes in unconventional reservoir development. To date, these advances have resulted from expert interpretation of microseismic maps, with the inclusion of data from other disciplines. This work has necessarily been subjective, qualitative, and dependant on the skill of the interpreter. New developments in geomechanical modelling which integrates the uninterpreted microseismic data, is now adding quantitative analysis, and directly incorporates multiple data types. This advancement enhances the predictive capabilities of microseismic analysis.
-
-
-
AVA and 3D VSP
By W.S. LeaneyWhile walkaways have been used to measure AVO for a long time and elastic properties have been recovered by inversion under an assumption of lateral invariance, the recovery of elastic properties away from the well is problematic due to the limited angular illumination provided by the typical multi-offset VSP geometry. Previous work on using walkaway VSPs for pre-stack elastic inversion made use of a 2D assumption and wavefield extrapolation to mimic a surface seismic geometry, but such approaches break down in 3D. In this paper the problem of AVA parameter estimation in multi-offset VSP imaging is studied using linear inverse theory and an algorithm that honours the true 3D VSP geometry is described that recovers information from AVA in pre-stack 3D VSP migrated images.
-
-
-
Interval Azimuthal Anisotropy from Walkaround VSP with Application in Marcellus Shale
Authors R. Zhou, B.A. Hardage and D. ShearerA walkaround VSP can provide local measurements of azimuthal anisotropy to characterize fractured rocks or stress fields around a well. When the acquisition is constrained to have irregular shot offsets, offset-dependent corrections are required. For an unconventional resource like the Marcellus Shale, a correction for background polar anisotropy is also necessary to effectively extract the azimuthal anisotropy around the well. This study introduces a procedure to remove the background VTI and overburden effects. Field data tests in the Marcellus Shale demonstrate that this new method can provide quantitative measure for the orientation and magnitude of fracture- or stress-induced local azimuthal anisotropy.
-
-
-
Borehole Seismic Application for the Qusaiba Shale Play in Saudi Arabia
Authors S. Berman and V. LesnikovUnderstanding seismic anisotropy is important for the exploration and development of unconventional shale gas reservoirs. Most shales are intrinsically anisotropic and the presence of thick layers of shale can cause defocusing of the seismic image and significant positioning errors of seismic reflectors. Moreover, anisotropy can have a major impact on the elastic inversion results and geomechanical analysis. The seismic anisotropy of shales results from a partial alignment of anisotropic plate-like clay minerals and can be approximated as vertically transverse isotropic (VTI) (Sayers, 2005). At the same time, shales may also exhibit azimuthal anisotropy associated with fractures and / or stresses. Borehole seismic data allows analysis of both VTI using walkaway VSP and azimuthal anisotropy using walkaround VSP. The Thomsen’s parameters (Thomsen, 1986) reliably estimated from VSP data can be used at different stages of exploration and development of unconventional reservoirs. The VSP results can also play an important role in the assistance of horizontal well placement by providing more accurate imaging of the vicinity of the borehole especially in anisotropic media (Berman et al, 2013). This is especially true in areas lacking 3D seismic data and well control. Another application of borehole seismic is providing critical information for microseismic monitoring of hydraulic fracturing. At the initial stage of downhole microseismic monitoring, VSP data can be used to assist in the optimal positioning of receivers in the lateral borehole and in the absence of perforation shots due to completion design, provide orientation of its horizontal components. During the processing and analysis of recorded microseismic data, VSP results help to build the anisotropic velocity model for a more accurate location of the microseismic events.
-
-
-
VSP Orthorhombic Anisotropy Inversion for Fractured Reservoir Characterization
More LessThe slowness-polarization method was developed to infer VTI/TTI anisotropy local to a walkaway receiver array, and successful case studies have been previously reported (Leaney and Hornby, 2007). We consider vertical orthorhombic anisotropy as the next target because a VTI formation under stress could present orthorhombic anisotropy with a vertical symmetry axis (VOR) due to stress-induced parallel vertical fractures in a background VTI medium. Usually, estimating lower symmetry anisotropy than VTI requires a 9C 3D VSP survey because quasi-P (qP) and two quasi-S waves are needed (Rusmanugroho and McMechan, 2012). However, if other measurements (walkaround VSP, fast and slow dipole sonic, microseismic, etc.) already constrain fracture azimuth, walkaway VSPs parallel and normal to the fracture strike will provide slowness – polarization evidence of vertical parallel fracture sets in VTI formations. We present VOR anisotropy slowness-polarization inversion using walkaways parallel and normal to the fracture strike acquired from a conventional P-wave source. Test results are presented.
-
-
-
The Study of Inverse Q-filter for Seismic Resolution Enhancement
Authors G.L. Zhang, X.M. Wang, Z.H. He, J.J. Zhang, H.J. Liu, Y.B. Zhang and Y.H. WangTheoretically, if we estimate accurate Q factor from VSP data and use it for inverse Q-filter in seismic data processing, then time-variant wavelet can be eliminated, and the resolution of seismic data can be enhanced. In order to control the numerical instability of inverse Q-filter amplitude compensation, a large number of papers studying the gain-limit constrained stable factor inverse Q-filter amplitude compensation method. But, the stable factor inverse Q-filter with the medium Q value cannot certainly improve the seismic data resolution, so we should study how to optimize the gain-limit and Q value estimated from zero-offset VSP data in order to improve the resolution and control the S/N ratio.In this paper, we focus on understanding the influence of the gain-limit and Q value, and introducing the select criterion of gain-limit and Q value. The result of synthetic data and VSP-driven inverse Q-filter for surface seismic data demonstrate that the select criterion is reliable.
-
-
-
Anisotropy Estimation in Lateral Inhomogeneous Velocity Model from Walkaway or 3DVSP Surveys
Authors M. Lou and F. DohertyWalkaway (WVSP) or 3DVSP provides a unique and highly valuable way to measure seismic anisotropy, because WVSP/3DVSP geometry is generally characterized by wide seismic-ray angle coverage and well-determined vertical velocities and first break (FB) times. Most of the available anisotropic inversion methods are valid only for flat-layered or lateral homogenous velocity models. However, anisotropic parameters in laterally inhomogeneous geological structures such as salt diapirs and faults must sometimes be estimated. Therefore, a new methodology was developed to estimate anisotropic parameters in lateral inhomogeneous velocity models. First, an anisotropic Eikonal solver (referred to as a fast marching (FM) scheme) is employed to efficiently and accurately calculate first break (FB) times in 2D or 3D grid-based inhomogeneous anisotropic velocity models. Then, a constrained global optimization algorithm known as simulated annealing (SA) is used to efficiently search and invert the anisotropic parameters based on the least square errors between calculated and observed FB times. A numerical example is used to demonstrate the feasibility of this methodology in estimating anisotropic parameters in lateral inhomogeneous anisotropic models from WVSP or 3DVSP survey.
-
-
-
3D VTI, Angle-dependent Imaging of PP Borehole Seismic Data
Authors M. Al-Bannagi, J. Owusu, B. El-Marhfoul and E. VerschuurWe extended 3D anisotropic Pre-Stack Depth Migration (PreSDM) to be applicable to borehole seismic data. We adjusted PreSDM to produce angle-dependent Common Image Point (CIP) gathers using both types of imaging conditions: cross-correlation and deconvolution. We demonstrate the effectiveness of our method with 3D borehole seismic data from the Arabian Gulf, Saudi Arabia. The deconvolution imaging condition yields well-balanced migration amplitudes and produces suitable CIP gathers for anisotropic velocity model building and pre-stack elastic inversion. The final migrated results show an enhanced image of the target sand stringers both in the immediate vicinity and away from the borehole.
-
-
-
Experimental Processing of Dual-well 3D DAS-VSP Simultaneously Acquired with OBS in Deep Water Environment in GOM
More LessA dual-well 3D DAS-VSP survey was simultaneously conducted by Shell with 2012 OBS survey in deep water in the Gulf Mexico. About 50 million traces were acquired in two wells, one is a near-vertical well and another is a strongly deviated well. Efficiently and effectively process of the large scale 3D DAS-VSP to obtain satisfactory subsurface seismic images is a great challenge. We developed the processing workflows for imaging, semi-automatic first arrival time (FAT) picking, and updating of velocity model with borehole seismic tomography inversions. The workflows were successfully applied to both wells to obtain RTM depth migrations with the VTI-initial model and VTI-inversion model derived with the borehole seismic tomography inversion. Our processing results demonstrate the ability of 3D DAS-VSP in providing higher frequency and higher resolution 3D RTM images of deep water reservoirs, possibly enabling 4D DAS-VSP as a cost-efficient, effective, on-demand monitoring technology for a deep water environment. It is found that the FAT diagnosis method can quantitatively diagnose velocity model uncertainties and monitor the process of velocity model updating. In this paper, we will present processing results of both wells and share our leanings from the 3D DAS-VSP processing practice.
-
-
-
Time Domain 3D VSP Processing as a Step Before 3D PSDM
Authors B. Fuller, M. Sterling, R. Van Dok and G. CaroIn nearly all cases within the seismic data processing industry, 3D Prestack Depth Migration (PSDM) of surface land and marine seismic data is preceded in the processing flow by time domain imaging steps. The time-domain steps include iterative NMO velocity analysis, residual statics and often 3D Prestack Time Migration (PSTM). The value of the time-domain steps is that source and receiver statics can be determined and a spatially variant 3D velocity field can be determined and later used in 3D PSDM steps. We have found that high quality 2D and 3D VSP PSDM results can be obtained by following the same time-then-depth process that is used in surface seismic data. Time-domain processing of 2D VSP and 3D VSP data is achieved by first applying upward continuation of the VSP data to effectively transform the VSP data into surface seismic data. The upward-continued VSP data can then be treated as surface seismic data, hence allowing computation of surface-consistent residual statics and development of a spatially variant time-domain stacking velocity field through NMO analysis. Then, in a process identical to that used in surface seismic data processing, PSDM can be applied to the upward-continued VSP dataset. By this procedure the same benefits of time-domain residual statics and velocity analysis can be realized for 2D VSP and 3D VSP data.
-
-
-
VSP Kirchhoff Migration with Structure Constraint
By X.Z. ZhaoExisting VSP Kirchhoff migration technique is combined with the structure dip information reduced from a newly developed structure tensor analysis (Jin et al., 2014) to improve image quality and allow for imaging dip structures away from the borehole. The HESS salt model is used to validate the improved VSP imaging results. The synthetic waveform data computed from the HESS model are migrated using the structure constrained Kirchhoff migration. The sub-salt structures and, especially, a dipping fault away from the borehole are clearly imaged. The image result is comparable to RTM but greatly improved from the conventional Kirchhoff migration method.
-
-
-
Investigating the Effect of Least-square Datuming on Imaging VSP Multiples
Authors A. Aldawood and I. HoteitApplying conventional cross-correlation based datuming of VSP multiples to obtain virtual SSP primaries yield virtual data that suffers from low resolution, correlation artefacts, and wavelet distortion. Least-square datuming could be used to deconvolve the acquisition fingerprint, suppress the artefacts, and enhance the resolution of the seismic events in the virtual SSP gathers. We imaged the virtual SSP primaries using Kirchhoff migration and noticed that the LSD enhanced the resolution of the subsurface structure.
-
-
-
My 3DVSP Image does not Look Like My 3D Seismic?
By E. Blias3D surface seismic data and 3DVSP data both provide velocity information and 3D images of the subsurface. In many cases however, 3DVSP and 3D seismic images are different. In this paper I explain the reason why one should not always expect subsurface images to be the same. With a 3DVSP survey, for each image point around the well, there is generally only one source-receiver azimuth contributing to this image point, while for 3D surface seismic, the image point is generally constructed from source-receiver pairs in multiple azimuths. Therefore, in an azimuthally anisotropic subsurface, 3DVSP and 3D surface seismic image amplitudes will be different. When recorded in environments that exhibit a strong AVO response, the absence of near zero-offset raypaths in 3DVSP data also leads to different image amplitudes compared to 3D surface seismic data which normally has close to zero-offset rays. It is shown that 3DVSP imaging is more sensitive to depth velocity model errors than is 3D surface seismic. 3DVSP data provides the most reliable interval orthorhombic parameters which should be used for both VSP and surface seismic processing and imaging. Reflected waves should be used when inverting traveltimes to improve the structural velocity model derived from 3DVSP data.
-
-
-
3DVSP for Imaging and Characterizing Shale Plays: A Seismic Simulation Driven Analysis Using the SEG-SEAM II Model
Authors P.N. Armstrong, H. Malcotti, A.V. Strudley and G. BallThe motivation of the work is to evaluate today’s 3D vertical seismic profile (3DVSP) technology driven by a 3D seismic simulation created using the SEG Advanced Modelling Program (SEAM) II model for a realistic unconventional development scenario. This knowledge will help the understanding of the value of a VSP for appraisal and development in shale plays in general, and specifically where the surface access is limited.
-
-
-
Processing 8 Wells DAS 3D VSP from South of Oman
By S.S. AlabriIn 2012 Petroleum Development Oman (PDO) tested acquiring a 2D walkway VSP in South Oman using fibre optics (DAS). The results from that test were encouraging such that PDO embarked on acquiring a full field 3D VSP survey using 8 wells in 2014. The aim of this survey is to serve as a base line survey for a 4D repeatability exercise to monitor steam injection in a heavy oil field. The survey was shot using 2 vibrators per single location and repeated 4 times to enhance the signal to noise ratio. Over 5000 shot locations were acquired in duration of 24 days covering a circular area of about 1km radius. The data was recorded simultaneously in 8 wells This paper present the processing annd merging of the 8 wells.
-
-
-
3D Joint Full Wavefield Imaging of Surface and VSP Data
Authors B. El-Marhfoul and D.J. VerschuurSurface seismic data can provide an image over an extended area. However, due to the involved two-way travel paths – including twice propagating through a possibly unconsolidated near-surface area– the resolution usually is quite limited. Borehole-related seismic data has a broader frequency band and better quality, resulting in a higher-resolution image. The main disadvantage of VSP data is the non-uniform fold distribution, which rapidly decreases while moving away from the well. This makes the areal extent of the final image very limited. In practice, VSP and surface seismic data are processed separately and the VSP image is spliced into the surface seismic data image. This workflow does not guarantee a perfect tie of the two images. In this paper we propose to employ both surface seismic and 3D VSP data simultaneously in one imaging process, such that – at least within an area around the well location – an optimum high-resolution image is obtained and the lateral continuity and consistency is guaranteed. Furthermore, by including all multiple scattering in a closed-loop imaging process – as proposed by the full wavefield migration process – a true amplitude reflectivity image will be obtained with high resolution and maximum lateral extent.
-
-
-
Detect Water Velocity Variations with Direct Arrivals and Water Bottom Multiples from 3D Subsurface Seismic OBN/DAS-VSP
More LessNodes (OBN) survey geometry is similar to that of the Vertical Seismic Profile (VSP), except no sensors in a borehole. Thus, VSP 3C analysis methods are applicable to 4C OBN. Li and Hewett (2013) developed a time-angle diagnosis method to quantify velocity uncertainties in a model using the VSP first arrival times (FAT) and first arrival angles (FAA). We applied this method to FAT/FAA from a 2012 OBN survey in the Gulf of Mexico to diagnose water velocity models and to detect spatial variations in the water velocity. Arrival times and angles of water bottom multiple (WBM), which was typically treated as “noise” to be eliminated, were used to characterize the water velocity uncertainties. We also investigated feasibility to use FAT and WBM from DAS-VSP concurrently acquired with the 2012 OBN to constrain the water velocity models. Diagnoses with OBN FAT indicate that the maximum RM of water velocity is -0.7% with a maximum 2-way time misfit up to ~12 ms, while OBN WBM analyses reveal lateral variation of water velocity is about +/-1%. A joint tomography using FAT/WBM from OBN/DAS/VSP is expected to be feasible for revealing details of spatial/time-variations of the water velocity.
-
-
-
Integrated Prestack Depth Migration of VSP and OBS Data in Angle Domain
By L. HuVertical Seismic Profiling (VSP) surveys not only generate higher fidelity data when compared with ocean bottom sensors (OBS), but VSP data can also be analyzed for reservoir properties via imaging and inversion for seismic attributes. This paper describes a Kirchhoff prestack depth migration (PSDM) technique for both VSP and OBS data using a common velocity model to produce angle domain common image gathers (ADCIGs) on a unified grid. Further processing of ADCIGs in a post-migration step is demonstrated to be an effective means of integrating partial images migrated for VSP and OBS data, and has produced results superior to the conventional workflow.
-
-
-
Use of VSP for Improving Drilling Decisions in the Bolivian Foothills
Authors V. Lesnikov, M. Verliac, J.F. Ballard and J.M. FleuryThe paper demonstrates successful application of the borehole seismic technology for subsurface imaging in the borehole vicinity and ahead of the bit to de-risk the sidetrack trajectory of the development well in the complex foothills environment. The VSP data acquired from the rig source and two fixed offset sources were rush processed and the processing results of a good quality became available for the interpretation within 24 hours from acquisition for each of three profiles. As a result of the borehole seismic data interpretation, the sidetrack has been drilled successfully reaching the Devonian fractured sandstone reservoir around predicted depth.
-
-
-
VSP Measurements used as a Tool in Sub Salt Field Development
Authors T. Bartels, M. Gelhaus and M. HumphriesMany of the Rotliegend low permeability dry gas fields in the Southern Permian Basin in northern Germany are covered by salt dome structures that lead to imaging problems in subsalt reservoir between 4000 m to 5000 m depth. As compartmentalization is the key challenge in field development high resolution seismic is essential for well planning. Only a vintage 3D seismic from 1993/94 with limited quality exists. Acquisition of new 3D seismic is not possible due to permitting restrictions and public resistance. Therefore the focus is on the acquisition of 2D VSPs in every new drilled well. The VSP measurements give local insights. With a general structural understanding and production history in mind those local insights can be merged into the overall picture and generate immense value for the understanding of the field.
-
-
-
3D VSP Benefits in Heavy Oil Field in South Oman
Authors F. Al-Kindi, J. Al Aamri, M. Al Amri, A. Al Aamri and S. BurnsOccidental conducted a program to test geophysical methods for reservoir surveillance and monitoring in a steam injection operation at a heavy oil field in Oman. This field is a Permian age Gharif reservoir. It consists of three stacked reservoirs with porosity range from 25-33%. The heavy oil is heated by steam to reduce its viscosity and to increase its mobility. Based upon forward modelling of the reservoirs, Occidental thought that the steam injection operations would induce changes in the reservoir properties that could be detectable by geophysical methods. Monitoring steam is believed to be a vital element in managing the steam injection to reduce cost and increase recovery factor. Feasibility studies done on well log data and core measurements showed that the compressional velocity decreases by 10-15 % due to steam injection. In 2005 a pilot geophysical monitoring program was started to test techniques with potential to detect the changes in the reservoir properties due to steam injection. A list of methods containing surface seismic, borehole seismic, passive seismic and geomechanical deformation methods was proposed. From 2005 to 2010 this intense program was conducted by doing three 2D offset VSPs, a tiltmeter survey, microseismic, six cross well tomography profiles and surface 4D seismic, as well as modelling and feasibility work. All of these techniques were tested over an active area of steam injection to maximize the possibility of observing reservoir changes. Results from each geophysical technique were correlated with other geophysical techniques results and with other surveillance results. An ambitious forward plan has been drawn based on the conclusions from this pilot monitoring program. This plan consists of applying the two geophysical techniques that showed encouraging results from pilot mode to implementation mode. Both VSP and cross well tomography showed that there is a change in reservoir properties matching the modelled response in magnitude and correlating very well with other surveillance measurements From 2011 to 2013 Oxy implemented a 3D VSP program aiming to evaluate the technical and operational difficulties that might be faced when using 3D VSP in optimizing steam injection and heavy oil production in this field. There are many uses of the 3D VSP so far. The data is being used to understand the steam distribution in the reservoir. This helped to identify injectors that could cause steam break through or hot fluids break through. This technology helped the engineers to identify the locations of cold areas and helped the planning of infill wells that would assist them draining these areas for better recovery.
-
-
-
Improving the Low-frequency Content of Borehole Seismic Data Acquired Using an Air-gun Source
Authors J. Tulett, R. Hearn, J.F. Hopperstad and T. DeanAbstract: The targets for offshore borehole seismic (BHS) surveys are becoming more challenging because they are deeper and overlain by more complex subsurface formations. Coupled with this is a move to more advanced acquisition methodologies such as 3D vertical seismic profile (VSP) surveys, as well as a desire for more powerful seismic sources that are also capable of generating wider-bandwidth data, in particular with increased low-frequency content. Low frequencies have a variety of benefits including overcoming the high-frequency attenuating effects of the Earth, improving vertical resolution, enhancing inversion results, and improving velocity analysis. A new BHS air-gun source array design has been introduced that significantly improves the low-frequency signal level but is a compact size that enhances the safety of deployment and towing.
-
-
-
Validation and Calibration of the SPWD-wireline Prototype for High-resolution Directional Seismic Imaging in Deep Borehole
Authors K. Jaksch, R. Giese, M. Groh, A. Jurczyk and K. KrügerThe project SPWD - Seismic Prediction While Drilling intends the development of a borehole prototype which combines seismic sources and receivers in one device to improve the seismic resolution and exploration depth by the application of a phased array technique for its magnetostrictive actuator sources. Within SPWD a wireline prototype has been designed, manufactured and tested. In May and September 2013 the pressure-tightness and the hydraulic system for coupling of the SPWD-prototype were proofed successfully at the KTB Deep Crustal Lab in Windischeschenbach (Germany) up to a depth of 2100 m. In 2014 3D-seismic measurements to calibrate the prototype have been carried out in the GFZ-Underground-Lab in Freiberg. The measurements applying different wavefield amplification directions show clearly dipping reflective structures depending on the amplified direction.
-
-
-
Land Seismic While Drilling: Guided Drilling to Reduce Depth Uncertainties. First in China
The Seismic While Driling technology is mainly for offshore use due seismic source limitation. In order to have fully syncronized acquisition of Checkshots, similar seismic source is required as in the offshore environment i.e Air Gun. The land operations puts more chalenges as compared to offshore operations. With good pre-job planning and collabration with different segments, the first land Seismic while drilling operation went successfully in two deep wells in Tarim basin, Noth West of China. Good quality Checkshots were obtained with both real-time and memory data, with excellent repeatibility. The quality of real-time data enabled to reduce the waiting time for model update and remigration of the data, which further reduce the turn around time for results delivery to driller to adjust the well trajectory in time and drill to the target safely.
-
-
-
Defining the Bandwidth of Vibroseis Sweep Data at the Target, not at the Source
Authors T. Dean, J. Tulett, D. Lane and M. PuckettHydraulic seismic vibrators are the preferred source for land vertical seismic profile (VSP) surveys. The introduction of new, more powerful vibrators wogether with the use of Maximum Displacement (MD) sweeps has resulted in the extension of the bandwidth from less than three octaves to nearly seven. One of the advantages of the design procedure for MD sweeps is that the spectrum of the resulting sweep is an input to, rather than a result of, the design process. This enables the design of sweeps where the spectrum contains sections of the bandwidth that have been enhanced. The data presented in this paper shows that the bandwidth of the data received downhole can be successfully adjusted by varying the power spectrum of the transmitted sweep. Even in highly attenuated terrains this enables us to transmit high frequency energy to significant depth.
-
-
-
VSP to Delineate Magmatic Bodies, Supercritical Fluids, Superheated Steam within Krafla Geothermal Field, NE-Iceland
Authors F. Kästner, S. Halldórsdóttir, G.P. Hersir, S. Planke, R. Giese, K. Gunnarsson, A. Gudmundsson, E. Juliusson and Ó.G. FlóvenzA VSP test experiment at the high temperature geothermal field Krafla in Iceland has been carried out. In two boreholes a zero-, far- and moving-source VSP has been applied to delineate subsurface fracture sets, zones of supercritical fluids, superheated steam and zones of magma with the background of a magmatic, high temperature and high attenuating basement. A careful preparation and evaluation of the survey is needed in order to provide a high resolution image of the surrounding subsurface. Under such special conditions high-quality three component data have been recorded and will grant a good basis for further processing and imaging techniques. It can be assumed that VSP techniques will provide a good alternative and addition to hitherto only applied surface seismic, teleseismic or microseismic procedures.
-
-
-
Wavenumber Response of Data Recorded Using Distributed Fibre-optic Systems
More LessDue to their ease of use, relative low cost, and excellent spatial sampling, distributed fibre-optic- based seismic acquisition systems are gaining increased attention, particularly in vertical seismic profile (VSP) surveys. Data recorded using such systems clearly exhibit a radiation pattern effect whose characteristics depend on the effective length of the section of fibre being used for sampling. The use of long gauge lengths results in the attenuation of high frequencies and high wavenumber whereas the use of short gauge lengths results in the attenuation of low frequencies and low wavenumbers. One solution to this problem would be to process data with a variety of different gauge lengths and merge the data at a later time. Unfortunately many of the systems currently available cannot offer this option because the length is fixed either by the hardware or within the initial processing.
-
-
-
1D Anisotropic Velocity Model Inversion from Multi-offset VSP Data Sets (Conventional Array and Optical Cable)
Authors P. Bettinelli and B. FrignetOptical seismic acquisition with distributed vibration sensing has been recently proposed to improve seismic acquisition efficiency (Hartog et al. 2013). An experimental multi-offset VSP data set has been acquired with both conventional and optical technologies in a 620-m-deep cased vertical well (Frignet and Hartog 2014). The 1D isotropic ray trace modelling times cannot be matched with picked transit times. It is necessary to introduce some VTI anisotropy to reconcile modelled and measured times at all offsets. Both conventional and optical VSP times were satisfactorily modelled with a 1D anisotropic model. Conventional multi-offset VSPs are not often acquired. In addition to the successful Thomsen anisotropic parameters inversion, an optical VSP acquisition is an order of magnitude faster than conventional acquisition. Therefore, multi-offset optical VSP could be routinely acquired in less time than conventional zero-offset VSP. Multi-offset VSP is a cost-effective technology for investigating velocity anisotropy in horizontally layered environments
-
-
-
Joint Study of 3D-VSP and Surface Full-azimuth Seismic in Northeast China
More LessGreat progress have been made on VSP techniques in recent years, especially the improvement of downhole geophone manufacture and VSP data processing methods. In XJWZ area of Daqing oil field, the reservoir is mainly formed by volcanic and its distribution is complex due to many periods of volcanic overlap in this area. Before this project is conducted, seismic surveys are mainly 2D and narrow azimuth 3D which are not suitable for anisotropy analysis and fracture identification. Therefore, a joint survey of 3D-VSP and full-azimuth surface seismic was implemented. This project tries to combine the advantages of VSP and surface seismic by 3D-VSP and full-azimuth surface seismic simultaneous survey. Q factor and anisotropy parameter estimated from VSP are applied to 3D seismic processing. Reservoir characterization and gas saturation prediction with final images shown encouraging results. Suggested well has been drilled and wet gas has been founded, so the validity of this method has been proved.
-
-
-
Reducing Velocity Model Uncertainty and Improving Microseismic Event Location Accuracy: Crosswell Seismic Tomography Using a Repeatable Sparker Source
More LessVelocity model errors are a major source of uncertainty in microseismic event location – a source of uncertainty that often goes unaddressed. This paper demonstrates how a commercial downhole sparker source can be used to produce crosswell tomography surveys that result in much improved velocity profiles. The combination of improved velocity model and more accurate event time picking deliver a much more constrained error distribution of micro seismic event location. This paper will outline a description of a repeatable and broadband downhole source, and the expected improvement to event location accuracy which is likely to be achieved, along with suggestions on how this may be applied to future monitoring surveys.
-
-
-
Remaining Gas Prediction with Walkaround VSP Data: A Case Study from Junggar Basin, China
Authors Y.H. Wang, Q.H. Zhang, Z.D. Cai, C.W. Liu and C. WangTwo VSP surveys were acquired around DX10 well in Junggar basin in 2004 and 2013, respectively. This study analyzed kinds of time-frequency attributes sensitive to gas reservoir from zero offset time-lapsed VSP data and walkaround VSP data. Reasonable estimation of the remaining gas distribution was derived with the hydrocarbon detection attributes, which is helpful for sidetrack well planning.
-
-
-
Traveltime Inversion of Walkaway VSP Data for a Model with Dipping TI Layers
By E. BliasWalkaway vertical seismic profiling (VSP) data potentially provides the most reliable anisotropy estimates. In many cases, a 1D model is not quite adequate for real data. If walkaway first break function is not symmetrical with respect to the well, then we need a velocity model with dipping/curvilinear boundaries. In this paper, I present a traveltime inversion approach for transverse isotropy (TI) parameter estimation that takes into account lateral velocity changes in the overburden. I describe these changes with dipping boundaries above the shallowest receiver. Dipping boundaries, interval velocities and anisotropic TI parameters in the overburden are included, together with simultaneous estimations of anisotropic parameters within the receiver array depth interval. Tests on model data show reliable anisotropy estimates. This approach was applied to multi-azimuthal walkaway data.
-
-
-
Orientation of 3 Component Rig-Source VSPs
Authors C. Naville, R. Tavernetti, M. Sweeney and K. KazemiAbout 75% of commercial borehole seismic operations are zero-offset VSPs, or “Rig-VSPs”. They are recorded before total completion in low deviated holes, with a deep open hole interval and a single casing, then multiple casing depth intervals above. Three components of geophones are recorded, with excellent mechanical tool coupling to the borehole wall, but usually the VSP tool cannot be oriented into geographical coordinates. Therefore only the Z-axis component is processed, or a near vertical component computed from the 3 recorded components, resulting in a reduction of the geological information derived from rig-VSPs. APS and IFPEN propose to implement current and future generations of VSP tools with cost effective fluxgates and inclinometers to improve the present situation.
-
-
-
3D 3C Walkaway to Calibrate Surface Seismic
Authors C. Naville, M. Denis, L. Nicoletis, P. Ricarte and E. SuaudeauImproved processing tools enable a new approach of complex land 3D VSP analysis. The first aim is to extract information useful for processing and interpretation of 3D surface data, the second one to obtain elastic wave fields (PP, P-SV, SV-SV, SH-SH) ready for imaging, from VSP data in 3 Components.
-