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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
1 - 20 of 40 results
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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