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Second EAGE Workshop on Borehole Geophysics
- Conference date: 21 Apr 2013 - 24 Apr 2013
- Location: St Julian's , Malta
- ISBN: 978-90-73834-46-0
- Published: 21 April 2013
42 results
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VSP Quantitative Diagnosis of Seismic Velocity Model for 3D VSP Imaging
More LessVelocity model building in the Gulf of Mexico is very challenging due to complex structures and salt resulting from poorly illuminated and noisy data. The predominately layered sand and shale geology introduces anisotropic effects which need to be included in the model building. Many combinations of velocities and anisotropy parameters can yield flat common image gathers after depth migration, and the ‘flat criteria’ is a non-unique solution assessing the quality of a velocity model. Due to uncertainties in the velocity models, we had poorly illuminated surface seismic images, especially in the sub-salt regions. Thus, 3D VSP are introduced intending to provide high-frequency/resolution images to complement the surface seismic. In this paper, we used multifarious VSP data in three wells to quantify the quality of surface seismic velocity models. Examples in the Gulf of Mexico are discussed where multiple surface seismic velocity models have been built, and several VSP data were used to quantify differences in those velocity models. The distributions of multi-VSP sources and multi-receivers also allow us to diagnose azimuth variations of the seismic velocity models. Our post-survey modelling practices have proven that multifarious VSP diagnosis method is a useful tool to guide the seismic velocity model updating.
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Efficient Wavefield Separation for Large 3D VSPs in Saudi Arabia
Authors C.A. Planchart, N.A. Palacios and J. JiaoFor large 3D VSP surveys that use large 3-component downhole receiver arrays to record of all the different wavefield components, it is not easy to apply conventional wavefield separation methods such as parametric decomposition or model based rotation. These methods usually fail for very large offsets because they are strongly dependent on the velocity model. In this paper we present a simple but efficient workflow for wavefield separation of large 3D VSPs. The workflow combines a wave-by-wave wavefield separation method with a covariance matrix method. The effectiveness of this technique is confirmed by application to 3D VSP data from Saudi Arabia.
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Efficient Vertical Seismic Profiling using Fiber-Optic Distributed Acoustic Sensing and Real-Time Processing
By D.A. BarfootRecent developments in fiber-optic sensing present the opportunity to use a fiber-optic cable as a distributed array of vibration or acoustic sensors, referred to as Distributed Acoustic Sensing (DAS). Using DAS for VSP surveys presents many new challenges and opportunities. We present methods to enhance data quality for VSP surveys by using real-time optimization along with fiber-optic distributed acoustic sensing.
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Simultaneous Multiwell VSP using Distributed Acoustic Sensing
Authors K.N. Madsen, S. Dümmong, T. Parker, D. Finfer, P.N. Travis, T. Bostick and M. ThompsonSimultaneous multiwell VSP data have been acquired using fibre optic cables in producing wells as distributed acoustic sensors. The measurement apparatus was retrofitted to the fibre optic cables installed for other purpose with completion of the wells. Data were acquired with no other instrumentation in the well and without disturbing the normal operation of the wells.
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Distributed Acoustic Sensing (DAS) for Reservoir Monitoring with VSP
Authors A. Mateeva, J. Mestayer, B. Cox, D. Kiyashchenko, P. Wills, S. Grandi, K. Hornman and J. LopezDistributed Acoustic Sensing (DAS) is a novel technology for seismic data acquisition, particularly suitable for VSP. It is a break-through for low-cost, on-demand, seismic monitoring of reservoirs, both onshore and offshore. We will briefly explain how DAS works, and then, demonstrate its usability for typical VSP applications such as checkshots, imaging, and time-lapse monitoring. We will show data examples from around the world, and discuss DAS as an enabler for full-field seismic monitoring with 3D VSP.
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VSP Multiple Analysis – An Arabian Gulf Case Study
By V. LesnikovThe paper discusses the application of VSP multiple analysis technique to guide multiple removal procedures in surface seismic and 3D VSP data processing. The results of the VSP multiple analysis from two wells in the Arabian Gulf helped explain the variability in the quality of the well-to-seismic ties across the OBC survey and optimize de-multiple workflows during the surface seismic data processing.
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Full Wavefield Migration of Vertical Seismic Profiling Data: Using all Multiples for Imaging Away from the Well
Authors A.K. Soni and D.J. VerschuurVSP data can provide a high-resolution reservoir image due to relatively lower wavefield distortion in the overburden. However, imaging VSP data using conventional primary-only migration suffers from poor illumination, imaging artifacts and low reliability, especially away from the well. Here, we are proposing the full wavefield migration (FWM) approach to image VSP data which aims at estimating the true-amplitude angle-dependent reflectivity of the subsurface using the primaries, surface and internal multiples. The FWM algorithm is recursive in depth and iteratively incorporates the nonlinear transmission effect at each depth level, followed by wavefield updating at each depth level. The use of the full wavefield in imaging the VSP data can enhance illumination and image reliability. The algorithm falls in the category of full waveform inversion – i.e. it explains every sample of the input data – using reflectivity as the parameters to be determined. It involves a constrained least-squares inversion approach, where all reflection energy is explained. Based on synthetic data studies, in this paper, we illustrate the advantage of using all multiples in this inversion-based migration scheme. We also demonstrate the potential of using deviated wells, as opposed to true vertical wells, for obtaining high resolution image of the complex reservoirs.
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Some Practical Aspects of Using VSP Interferometry in Horizontal Wells for Imaging Above and Below the Wellbore
By M.E. WillisWith the increased number of horizontal wells being used to produce unconventional plays, there is a growing inventory of wells that can benefit from the use of interferometric processing methods. Seismic interferometry for VSPs in horizontal wells can move the surface shots to behave as if they are located at the positions of the receivers in the borehole. It removes the overburden travel path from the redatumed traces without using any velocity information or even surface shot statics. So an image can be made below the borehole using only the local velocity near the borehole. The added benefit of redatuming the shots into the borehole is that the upcoming reflected energy from changes in the lithology below the borehole can act like deep seismic sources allowing imaging of events above the borehole. It is also possible to redatum the receivers to the surface, making each shot into a receiver. This transforms the VSP data set into surface seismic data. I present some practical aspects of the method using synthetic examples to create a more intuitive understanding of the method.
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What Constitutes A Good Microseismic Acquisition System?
Authors S.C. Maxwell, B. Underhill, L. Bennett and A. CatoiIn this paper, characteristics of an ideal microseismic acquisition system are described. Key sensor specifications are discussed with a view to record high quality signals including adequate bandwidth to cover the dominant spectral frequency content, sensitivity to record signals in the presence of background noise, dynamic range to record large and small amplitude signals, non-distortive response free of resonances and spurious frequencies and vector fidelity of 3C sensors to determine the raypath orientation to locate the microseismic source from a single well.
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VSP in a Microseismic World
By M. HumphriesThe development of long arrays of; non-permanent, 3-component, high pressure, high temperature down-hole receivers, was escalated in the 1990s by the requirements of Vertical Seismic Profile (VSP) recording. The advent of such arrays increased the feasibility of acquiring micro-seismic surveys. Micro-seismic events are generated in many ways and even small movements in rocks will generate micro-seismic events. Some basic micro-seismic processing is covered before describing some of the many links between VSP and micro-seismic. Many opportunities have been opened up to extend 3D VSP techniques as a result of shared acquisition with micro-seismic monitoring.
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Application of Compressive Sensing to 3D-VSP Acquisition and Processing
By L.C. MorleyFrom the viewpoint of classical sampling theory, 3D-VSP surveys are normally under-sampled over the shot and receiver axes. Because of this, strong acquisition footprints are commonly seen on migrated 3D depth slices in both pre- and post-stack domains. These image artefacts are usually considered to be acceptable, since they typically don’t prevent the asset team from deciding on further drilling objectives and mitigation via increased source effort is very costly. It has been recognized for some time that conventional offset VSP images can be improved by irregular depth sampling of borehole receivers. More recently, it was discovered that image improvements from randomized sampling can be understood through the theory of compressive sensing (CS) and that source-axis bandwidth can also be improved by irregular sampling of the surface shot locations. Survey spatial bandwidth is, in fact, optimized in the CS sense when shot sampling is chosen to have “minimum mutual coherence” Candes and Wakin (2008), Tang et al (2008). Improved bandwidth for equivalent source effort is one important use of compressive sampling. The big win for 3D-VSP, however, is that CS can also be used to separate or “de-blend” two or more independent sources acquired simultaneously in time. This technique is a particularly cost-effective application when source acquisition costs are dominated by rig time and can be extremely high.
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VSP Based Seismic Velocity Correction in VTI Media
More LessTechniques for computation and correction of NMO velocities in VTI media are widely employed. However, there are discrepancies between the anisotropic parameter η values computed based on VSP data and those based on surface seismic data; this prevents the direct use of VSP-derived η values in surface seismic data processing. This paper discusses the causes of these discrepancies and proposes methods for compensating for them using actual full-azimuth seismic data, zero-offset VSP data, and Walkaway VSP data from an oil field in China. Our studies indicate that conventional computation of Vnmo, (based on the horizontal layered media and isotropy assumption, using the conventional NMO formula within a small offset range and relying on the principle of flattening CMP gathers), does not yield correct anisotropic parameters, In practice, surface seismic velocity must be corrected with the velocity computed using zero-offset VSP data. Surface seismic data are then corrected using VTI anisotropic parameters computed based on Walkaway VSP data and accurate seismic imaging results can be achieved.
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Estimating Anisotropic Parameters from Walkaway VSP Data using Genetic Algorithms
Authors M. Bannagi and J. OwusuIn this abstract, a new approach to calculate the anisotropic parameters from walkaway VSP data is presented. A global optimization technique based on genetic algorithms is used to estimate the normal move-out (NMO) velocity and the non-hyperbolic parameter from a three-term NMO approximation. Then, interval anisotropic parameters are calculated. The test results of this algorithm on several NMO approximations are presented.
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Interval Q-factor Estimation from Zero-Offset VSP Data
By E. BliasInelastic attenuation, quantified by Q, the seismic quality factor, has considerable impact on surface seismic reflection data. A new method for interval Q-factor estimation using near-offset VSP data is based on an objective function minimization measuring the difference between cumulative Q estimates and those calculated through interval Qs. To calculate interval Q, we use all receiver pairs that provide reasonable Q values. To estimate Q between two receiver levels, we use directly the equation that links amplitudes at different levels and can provide more accurate Q values than the spectral ratio method. To improve interval Q-estimates, which rely on travel times, we use a high-accuracy approach in the frequency domain to determine time shifts. Application of this method to real data demonstrates reasonable correspondence between Q estimates and log data.
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Joint Prospecting of a Volcanic Reservoir with VSP and Surface Seismic Data
More LessVolcanic reservoir exploration is quite challenging due to its rapid inherent velocity variation. The paper presents a case study of a gas-bearing volcanic reservoir, where zero-offset VSP, Walkaway VSP with eight azimuths, simultaneous 3D VSP and full-azimuth surface seismic data were acquired. A VSP-driven surface seismic data processing workflow was introduced to obtain a better image of the reservoir. Rather than conventional way of using VSP data for geologic body delineation, this workflow utilized VSP data to estimate parameters for surface seismic processing. Based on this workflow, the surface seismic data were processed and then used to estimate Poisson's ratio cube and fracture maps amenable for prediction of gas distribution in the reservoir. We demonstrated that the newly-processed surface seismic data with VSP-driven workflow are more reliable than that without assistance of VSP data, which can also be applied to other gas-bearing unconventional reservoirs.
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Observation of Shear-Wave Splitting and Dispersion in Walkaround VSP Data from Saudi Arabia
More LessShear waves propagating through an anisotropic medium split into two approximately orthogonal phases with different velocities. For a single set of fractures, the faster shear wave is polarized along the fracture planes, while the slower shear wave is polarized in a direction orthogonal to the fracture planes. For multiple sets of fractures, the faster shear is not polarized along one specific fracture plane. In this paper, shear-wave splitting analysis for walkaround VSP data was applied for the characterization of multiple sets fractures. Dispersion of the downgoing S- and reflected P-waves was also investigated as a way to discriminate between open and closed fractures.
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Anisotropic Full Waveform Inversion of Walkaway VSP data from the Arabian Gulf
Authors O. Podgornova, J.C. Owusu, M. Charara, S. Leaney, A. Campbell, S. Ali, I. Borodin, L. Nutt and H. MenkitiFull waveform inversion (FWI) is a powerful technology for the estimation of subsurface elastic parameters. Recently, an elastic FWI method was applied to a Walkaway VSP dataset that was extracted from a larger 3D VSP survey located in the Arabia Gulf, offshore Saudi Arabia. This work is part of a larger feasibility study to detect and map very thin sand stringers located in a sand-shale geologic environment where the P impedance contrasts are low. The ultimate objective of this study is to derive high resolution P, PS and Vp/Vs images from the larger 3D VSP survey for the placement of horizontal wells. This paper presents interim results from this feasibility study using only frequencies up to 40 Hz for the FWI. We will discuss the results of using a vertically transverse isotropic (VTI) anisotropic elastic model of the Earth that reproduces the data fairly well, and is geologically consistent when compared to other independent measurements, such as sonic logs.
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Feasibility and Benchmarking of Time-Lapse 3D VSP in Water Flood Surveillance
More LessAlthough 3D surface seismic imaging has been the primary tool for geophysical reservoir monitoring to date, vertical seismic profiling (VSP) has characteristics that make this technology an attractive proposition for time-lapse monitoring. However, 3D VSPs are not yet widely applied for time-lapse (4D) monitoring. To better understand the value of this technology as a potential 4D reservoir monitoring tool for a waterflood surveillance project, we conducted a comprehensive feasibility study. Through this study we have been able to compare and contrast 3D/4D VSP data processing capabilities of a few vendors in the industry.
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Reservoir Monitoring of SAGD using Repeated Dual-Well 3D VSP Measurements. A Case Study after 10 months of Production
Authors R. Tøndel, S. Dümmong, L. Nutt, R. Rufino and A. CampbellTwo 3D VSP surveys have been acquired over Statoil and PTTEP's Leismer Demonstration Area in the Canadian Athabasca Oil Sands region, aiming at monitoring parts of the reservoir during steam assisted gravity drainage. Within the framework of a Statoil-Schlumberger cross-well collaboration project, careful survey planning, accurate acquisition setup and thorough time-lapse processing have provided seismic data with clearly visible production-induced differences, after only 10 months of production.
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Monitoring CO2 Injection at the Illinois Basin -- Decatur Project with Time-lapse 3D VSPs
Authors M. L. Couëslan, J. Gulati, A. Campbell and L. NuttTime-lapse three-dimensional (3D) vertical seismic profiles (VSPs) are an important component of the monitoring, verification, and accounting plan for the Illinois Basin –- Decatur Project. The VSPs will be used to provide information on CO2 plume development, demonstrate containment of the CO2 in the storage formation, and provide data to verify and update models and simulations over the life of the project. VSPs are more economical to acquire and process than surface seismic data and cause less disruption to local landowners as they have smaller acquisition footprints. The 3D VSPs are being acquired with a permanent geophone array. Three 3D VSP surveys have been acquired at the site to date: two baseline surveys and one monitoring survey acquired after ~70,000 tonnes of CO2 had been injected. Baseline 2 and Monitoring Survey 1 data have high repeatability as evidenced by the NRMs repeatability metrics. The final difference displays do not provide conclusive results regarding CO2 movement in the Mt. Simon formation; however, the NRMS depth slice at the injection interval shows higher NRMS values that may be suggestive of the presence of CO2. Future surveys are expected to produce more conclusive results as the volume of injected CO2 increases.
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VSP While Drilling: A Deepwater Case Study Offshore West Africa
Authors J. Kemper, A. Jervis, M. Richards, J.-C. Puech and N. KelsallRank wildcat wells in deepwater represent some of the greatest opportunities for operators today but also present major challenges. 3D surface seismic velocity data without nearby well calibration has significant uncertainty from the conversion of two-way time to horizon depths, which further induces risk in the predrill pore pressure model created from limited available data. This case study is about a deepwater exploration well drilled offshore West Africa where seismic while drilling technology was used extensively to reduce depth uncertainties and drilling risks from spudding to total depth of the well. This allowed for the target depth uncertainty to be reduced by more than 90% along the three consecutive drilled sections, from greater than +/-100 meters to less than +/-5 meters. Furthermore it allowed this 2D well trajectory to avoid accidental penetration of the first target, avoiding a kick and placing the 13 3/8” casing shoe safely above the first target, 80 meters shallower than predicted, and just 20 meters from the top formation. Placing the 13 3/8” casing shoe as deep as possible increased the mud weight window for the 12 1/4” hole section, and contributed towards saving a casing string close to the bottom of the well.
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Landing a Horizontal Well with the Assistance of 2D VSP
Authors S. Berman, V. Lesnikov, T. Duncan and R. WilliamsThis paper describes the uncertainties associated with determining an appropriate dip to geosteer a well towards the landing zone and along the well trajectory, and how a 2D VSP helped. Various methods of pre-drill dip estimation are discussed and compared to the 2D VSP and to LWD measurements.
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Advanced Borehole Seismic Imaging of Transition-Zone Subsurface Structures
Authors T. Radford, M. Karrenbach and F. YustianaTransition zone seismic surveys collected over a subsurface reef structure present significant subsurface imaging challenges in producing reliable interpretations for reservoir assessment. In order to aid the reservoir description, the complete vertical and horizontal borehole trajectory was instrumented with 3C receivers, while simultaneously recording 3C receivers in shallow vertical wells. Even with a limited source layout, such a source and receiver geometry allows us to extract a multitude of information about the near surface and deeper subsurface. While traditional standard imaging is challenging with this geometry, interferometric processing, imaging and analysis allows us to obtain valuable reservoir information. In the following we briefly introduce the geologic setting and data acquisition aspects, and focus on the results obtained by using advanced processing flows, such 3D velocity model construction using nonlinear travel-time tomography, interferometric seismic gather generation and depth imaging, as well as elastic full wave form forward modelling to help in the interpretation, analysis and uncertainty estimates.
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Simulation and Proposed Processing Workflow of Simultaneous Source 3DVSP Data
Authors M. Atif Nawaz and W.H. BorlandSimultaneous source acquisition is a method that is currently being accepted as the way of reducing the acquisition time and hence related cost, for both surface and borehole seismic (3DVSP). It is critically important for 3DVSP because of high cost of offshore rigs. Two or more sources can be used with a predifined firing delay. The delay time of firings is chosen as a random function from shot to shot. The data thus acquired as the blended respose of multiple sources. Surface seismic data acquired with simultaneous sources can exploit random delays to separate the respose of multiple sources in receiver domain. In borehole seismic, receiver domain separation, however, poses other challenges like separation of downgoing and upgoing wavefields. New methods are proposed to separate simultaneous sources response in the source domain. The methods prove successfull and open new frontiers for efficient and cost-wise feasible acquisition and processing of 3DVSP data.
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Kirchhoff Prestack Depth Migration of 3D VSP Data in Offset and Angle Domains
By L. HuShallow unconsolidated sediments, irregular refractors, rapid surface elevation changes and hidden karsts are geologic features in the Middle East that can significantly degrade the quality of recorded seismic data. Accurate handling of these complexities is critical for seismic interpretation as low relief structures, stratigraphic traps and fractures have become important exploration targets. Vertical Seismic Profiling (VSP) not only generates higher fidelity data when compared with surface seismic surveys, but VSP data can also be analyzed for reservoir properties via imaging, modeling and inversion for various seismic attributes. This paper describes a Kirchhoff prestack depth migration (PSDM) technique for 3D VSP data to produce common image gathers (CIGs) in both offset and angle domains. The offset domain CIGs are for use in migration velocity analysis (MVA) and the angle domain CIGs (ADCIGs) are for use in modeling and elastic inversion for reservoir properties. This extended Kirchhoff PSDM technique was applied for both synthetic and real data examples and the initial results are promising.
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Improving the Low-Frequency Content of Land VSP Data Acquired using a Vibroseis Source
Authors M. Puckett, T. Dean, J. Quigley, D. Lane and J. TulettThe targets for VSP surveys are becoming more challenging, being deeper and overlain by more complex sub-surface formations. Coupled with this is a move to more complex acquisition methodologies, 3D VSPs in particular, and a desire for wider bandwidth data, in particular enhanced low-frequency content. As the preferred source for land VSP surveys is the seismic vibrator there is a requirement for vibrators to be able to emit lower frequencies than has previously been possible. Emitting such frequencies requires a sweep design methodology that takes into account the mechanical, hydraulic and control electronics limitations of the vibrator. Through measurements made both at the vibrator and downhole we show that Maximum Displacement Sweeps can be successfully employed to considerably increase bandwidth.
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Portable Airgun Tank - A New Approach to Land BHS using Airguns
More LessThe Portable Airgun Tank (PAT) is a new approach to land Borehole Seismic surveys when using airguns. The PAT is a water filled surface mounted flexible tank which is fully portable and reusable with different sizes available to suit particular applications. Once water filled an airgun source is deployed and centred in the tank. The PAT offer a very constant source signature on every shot.
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Drill-Bit Seismic While Drilling by Downhole Wired Pipe Telemetry
Authors F. Poletto, F. Miranda, P. Corubolo, A. Schleifer and P. ComelliDrill-bit seismic while drilling provides reverse VSP, makes it possible to predict the formation changes ahead of the bit, and to image 2D and 3D structures without interference with drilling activity. When the pilot signals used for crosscorrelation with the seismic signals are recorded at the surface, an issue in the application of this methodology may be the loss of the drill-bit-vibration signal during its propagation from the bottom to the surface through the drill string. With PDC bits, as well as during drilling by sliding condition without pipe rotation, and in highly deviated or horizontal wells, the pilot signal recorded at the surface may be weak and consequently the SWD results poor. A solution is to use near-bit downhole tools to get good-quality measurements of the pilot signal. Literature reports examples of SWD with the use of downhole memory systems, from which the data are downloaded after the bit retrieval at the surface. In this paper we present the new results obtained using a drill pipe equipped with a wireline communication system from bottom hole to the surface. The results demonstrate the applicability of this method providing good-quality RVSP data, in terms of S/N and frequency content.
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New Moveout Approximation for Walkaway VSP Geometry in a 3D Anisotropic Model
By E. BliasI introduce a new explicit form of vertical seismic profile (VSP) traveltime approximation for a 3D model with non-horizontal boundaries and anisotropic layers. The goal of the new approximation is to dramatically decrease cost of time calculations by reducing the number of calculated rays in a complex multi-layered anisotropic model for VSP walkaway data with many sources. This traveltime approximation extends the generalized moveout approximation proposed by Fomel and Stovas. The new equation is designed for borehole seismic geometry where the receivers are placed in a well while the sources are on the surface. Testing this new approximation for the 3D anisotropic model with dipping boundaries shows its very high accuracy for offsets up to three depths. The new approximation can be used for 3D anisotropic models with tilted symmetry axes for practical VSP geometry calculations. The new explicit approximation eliminates the need of massive raytracing in a complicated velocity model for multi-source VSP surveys.
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The Theory and Application of Layer Q Inversion Based on VSP Data
More LessAccording to the compensation principle of surface energy consistency, this paper described a method to eliminate the difference of the excitation energy in zero-offset VSP data, and then use the FK method to separate the down-going wavefield with amplitude preserved processing. Through the analyzing of the difference of amplitude spectra between selected down-going wavefield and monitoring wavelet, we removed the variation of source wavelet in the Q inversion results. After combined with the analytical method, we obtained reasonable equivalent Q values. Based on the relationship between layer Q and equivalent Q, we achieved the stable layer Q values. By working through the contrast between the estimated layer Q and interval velocity, and the results of inverse Q filtered to VSP and near-well surface seismic data for amplitude compensation, we have achieved following improvements: (1) the inversed layer Q and layer velocity are very similar; (2) inverse Q filtering broadened the data spectrum, enhanced the dominant frequency, and improved the seismic resolution greatly; (3) the real data examples showed that this layer Q inversion method is reasonable, effective and stable.
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Long offset walkaway and circle VSP in Nankai trough seismogenic zone
Authors Y. Sanada, R. Hino, M. Kinoshita, J.O. Park, E. Araki, G. Moore, N. Bangs, R. von Huene, T. Tsuji and S. KodairaThe purpose of this VSP surveys is to illuminate deep plate boundary and mega-splay faults with high resolution imaging, and to build Vp and Vs model in this area. The seismic data were successfully acquired with the 53.4km walkaway VSP and the circular VSP with 3.5km radius with 16 three-component wireline borehole seismic tools in the cased hole. Zero offset VSP were carried out as well. The long offset survey like this long distance and deep target was first-ever carried out in academia and industrial field. Preliminary P-P reflection image shows high resolution reflections from splay faults. Anisotropy results using direct arrival time from circle VSP indicate anisotropy and its orientation is consistent with the orientation of Philippine plate subduction and the stress orientation from bore hole image. We are planning 3D spiral VSP in 2013.
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A High-Resolution Seismic Investigation of the Borehole Surrounding with the Seismic Directional SPWD-Method
More LessIn borehole seismics several methods are in use while drilling. In the case of small layer structures, for instance thin layers or faults, the resolution of surface seismic methods is often not sufficient to determine and locate these structures for exploration. Combining a seismic source and receiver in a common device in the drill string would increase the seismic resolution. In the project SPWD such a prototype of a device has been designed, manufactured and tested. The used source signal frequencies are up to 5000 Hz, which allows a resolution of up to one metre. The resolution is therefore significantly higher than for VSP and SWD. With a penetration depth of about 100 metres an exploration of the borehole surrounding is possible. By applying this method while drilling the risks and costs of drilling can be minimized because of the possibility of adjusting the drill path and locating small sought-after structures.
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Equipment Testing and Optimization for Borehole Seismic Monitoring
Authors I.M. Geldmacher, A. Marr, J. Rangel and B. DyerWith the advent of strong interests everywhere into unconventional – speak “shale” – reservoirs, the discipline of borehole geophysics is experiencing a remarkable renaissance. Particularly the fields of microseismic (MS) and vertical seismic profiling (VSP) are showing strong activities worldwide. Regardless whether one looks at MS or VSP, in order to properly interpret these borehole seismic data, one needs to rely on an optimal performance of the recording unit. While some parameters, such as sensor orientation or system noise levels, can be site dependent, there are a number of parameters the operator can influence to achieve a superior data record; laying the ground work for a more accurate event location or velocity model. In this work we present the results of a survey comparing a number of different downhole sensor arrays, excitation mechanisms and operational mechanics, with the goal to identify superior and inferior areas for the tools. The test was set up using a three well set up. The center well was used as a control well to obtain measurements that allowed us to use comparisons from consistent source readings. Those consistent source readings were compared with respect to the various arrays tested.
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4D Passive and Aggressive Monitoring of Air Injection into Top Water Overlaying Bitumen Telephone Lake, Alberta
Authors R.D. Pearcy and L. MayoAs part of an air injection monitoring exercise in Telephone Lake area of Northern Alberta, a high resolution simultaneous surface 3D and downhole survey was acquired to map the extent of the water displacement with in the bitumen zone.
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Acoustic Impedance Inversion of VSP data
More LessDuring the drilling stage, VSP plays an important role in predicting the depth of target strata and the lithologic characteristics of the deep strata ahead of the drill bit. Therefore, using VSP data to predict ahead of the drill bit has become a popular topic. Highly precised acoustic impedance inversion is a key technique for ahead of drill bit prediction using VSP data. In this paper, we have proposed a method of predicting the acoustic impedance in the formation ahead of the drill bit using VSP data. First, the nonlinear iterative inversion is adopted to invert for acoustic impedance using the VSP corridor stack. Then, by modifying the damping factor in the iteration and using the preconditioned conjugate gradient method to solve the equations, the stability and convergence of the inversion results can be significantly enhanced. The results from theoretical models and real data demonstrate that the method is very useful and effective for ahead of drill bit prediction using VSP data.
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A High Resolution VSP in the Oil Sands for Improved Reservoir Characterization
Authors M.H.L. Morrish and L.M. Weston BellmanThis is a case study that looks at the application of a high resolution multi-component VSP acquired in the Athabasca Oil Sands Region of Canada. The 2D Walkaway VSP was the first to be acquired using a new type of downhole array capable of over 2,000 channels of 3-component data per borehole. The HDVSP™ array is based on the VectorSeis® MEMS sensors, which are deployed at either 1 or 2-metre intervals from the surface to the bottom of the well. For this case study, 141 3C sensors were deployed in the well at 2m intervals. The Athabasca oil sands region is an area with complex reservoirs, complex fluid distributions and unconventional rock property behavior. High quality shallow multi-component seismic data contributes to the conditions required for unprecedented detail in reservoir characterization, enabling accurate predictions of both lithology and fluids. The incorporation of converted-wave data shows how an under-utilized dimension of seismic data can increase the quality of the solution. The VSP data was used to improve the seismic reservoir characterization by enabling high-quality calibration and integration of the converted shear (PS) data with the conventional P-wave (PP) data obtained from the multi-component 3D surface seismic.
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3D Spectral Element Method in Anisotropic Viscoelastic Media for Borehole Seismic
Authors M. Charara, D. Sabitov and G. PekarWe present an efficient and accurate numerical algorithm for the simulation of borehole seismic experiments. The basis of the approach is a heterogeneous spectral element method implemented on multi-GPU applied to elastic wave equation. The approach was designed to simulate wave propagation in 3D arbitrary anisotropic elastic media with attenuation for a constant via standard linear solid using the method. Due to the use of an unstructured grid, the spectral element algorithm enables handling geological models of big complexity.
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3D-VSP Design Acquisition for Monitoring In Situ Combustion. A Case Study: Llanos Basin Colombia
More LessIn order to monitoring the combustion in-situ in a field, we decide to use the 3D-VSP technique such that it could be repeated several times during the field development. The selection was based on (1) area target extension, (2) monitoring wells distribution, (3) thickness target affected by air injection and (4) vertical and horizontal resolution required. The goal of this work is select the parameters which allow both, right target illumination and repeatability. The 3D-VSP design strategy was analyzing the sensibility of the acquisition parameter and performs geophysical modeling by ray tracing. During sensibility analysis the source distribution (geometry) and the number and depth levels were perturbed. The depth level is a critical parameter for repeatability; because of the possible damage induced by combustion to the formation. Additionally, ray tracing was performed on the structural model to quantify the optimal source distribution and the optimal source density. Variability of parameters was evaluated as a function of the homogeneity coverage. Finally the optimized acquisition geometry includes results from sensibility analysis and geophysical modeling processes
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Ray-Based Approaches to 3D VSP Modelling for Survey Planning and Interpretation
Authors L. Zühlsdorff and Å. DrottningAdvanced seismic modelling is the key to survey evaluation and design. Two different but complementary ray-based methods are presented: (1) the classic ray-tracing approach with a focus on illumination mapping and attribute filtering, and (2) simulation of depth migrated seismic images of the reservoir as based on illumination vectors. Combining these methods, shot and receiver positions can be optimized, fold and amplitude at target level can be verified, both lateral and vertical resolution can be estimated, and final seismic (depth migrated) images can be simulated and compared for a given survey setup and various overburden properties. Examples are shown for a 3D VSP case and an ocean bottom cable reference case.
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3D PSDM Model Building in a Well-Rich Environment
Authors D.C. Weber and V. LesnikovThe paper describes velocity-depth model building for a marine 3D VSP survey in the Arabian Gulf. OBC seismic data exists but is of poor S/N and contaminated with multiples. We construct a P-wave velocity-depth model using only VSP checkshots and well tops from wireline. The checkshots provide P-wave velocity control and the well tops define the depth intervals. First, well tops are gridded in 3D to extrapolate continuous surfaces over the depth volume. Then time-depth information from checkshots is converted to interval velocity functions at each well. Finally, interval velocity is gridded and smoothed in 3D. The composition of all the layers yield the P-wave model. The P-wave model was used to perform pre-stack depth migration on P-wave gathers from a 3D VSP survey. Model accuracy was verified by QC of common image point gathers. We then use wireline Vp/Vs ratio from area wells as a scaler to convert the P-wave model to S-wave. A Vp/Vs volume was built using 3D kriging of the Vp/Vs ratio logs from available wells. The Vp/Vs volume was then divided into the P-wave volume to yield the S-Wave volume. PSDM results using the S-wave model on S-wave gathers are not currently available.
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An Amplitude Scaling Methodology for 2D/3D Migrated VSP Data
Authors M. Lou, J. Meng, D. Cheng and F. DohertyVSP data can provide a significantly high resolution image. However, VSP data is characterized by a highly uneven distribution of both CDP fold and reflection incident angles laterally away from the borehole. One end effect of this uneven distribution is a migration image characterized by amplitude decay as a function of offset from borehole in migrated VSP data. This paper presents an amplitude scaling methodology to compensate the offset-dependent amplitude decay. We first locate a geologically stable and flat event above a target zone, and calculate its RMS amplitude distribution as a function of offset. From calculated RMS amplitudes we then characterize the amplitude-decay pattern by least-squares fitting. While each dataset may be analysed by various polynomial or Gaussian functions for best fit, this paper we suggest the amplitude-decay pattern can be characterized by a four-term Gaussian function. Finally, by reversing the best fit function, an amplitude scaling factor is applied to each trace of the migrated VSP data. We demonstrate the methodology greatly enhances the dimming amplitudes at long offsets in migrated VSP data. The amplitude distribution of migrated events after scaling is laterally more homogenous, potentially allowing the data to be used for lithological inversion and interpretation.
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Transmission Amplitude Variation with Offset (TAVO)
Authors A.A. Al-Shuhail and A.K. PopoolaThis study presents new approximations for the transmission PP and PS coefficients from Zoeppritz equations. The approximations are presented in a form that is convenient for conventional AVO analysis. The expressions are tested using several reservoir models by comparing their performance to their corresponding Zoeppritz expressions. Results show that a one-term approximation is good at small to intermediate incidence angles while two or three terms might be required at large incidence angles approaching the critical angle. We show also that using higher number of terms does not improve the results. The presented approximations are ideal for use with VSP geometry and offer several advantages over existing reflected AVO analysis.
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