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Results
Azimuthal Seismic Pilot for Fault and Fracture Detection - An Abu Dhabi, U.A.E. Case Study
Mueller, Klaus W. (ADCO) | Nahhas, Mohamad Samir (ADCO) | Soroka, William L. (ADCO) | al Baloushi, Mariam (ADCO) | Sinno, Rick (PGS) | Martinez, Ruben D. (PGS) | Hussein, Waleed (PGS) | LeCocq, Paul (PGS)
Abstract An azimuth dependant processing pilot study was carried out in a large Middle East Field to evaluate if this technology has the potential to successfully identify fracture permeability pathways. The field is heavily faulted and fractured with good well control and therefore is a good candidate to perform this study. The success criteria for the Azimuthal processing are: Improved fault imaging relative to the available conventional processed seismic volume; Obtain information about seismic anisotropy in the reservoir zones. This anisotropy will be linked in a full evaluation to fault & fracture density and orientation. The anisotropy can be measured via differences in seismic travel times or amplitudes / seismic attributes measured in the different azimuth seismic cubes. Azimuthal anisotropy from a 3D land seismic dataset acquired in the U.A.E. has been analyzed using wide azimuth processing. Two different processing methods and flows were tested to derive optimum processed volumes. In both methods raw CMP gathers, after convolution, residual statics, and inter-bed multiple elimination were used as input data for the azimuth stack processing sequence. The two methods are Azimuth Sectoring Common Cartesian Offset Bins (CCOB) Both processing methods have their benefits, one big advantage of CCOB is that you can stack very fast different individual azimuths together and get a sharper image, which results in better interpretation. Azimuth sectors both parallel and perpendicular to the three major fault system orientations, were imaged separately to produce the six final azimuth volumes. Comparisons between the different azimuth sectors were used to detect azimuthal differences in velocities and amplitudes that could be correlated with fault and fracture orientation and magnitude. The interpretation and validation of the results suggest that value is maximized by integrating multiple attributes that include horizon mapping for time differences, amplitude extractions for reflectivity differences and result validations with available well calibration. The azimuth sector results have aided in the quantification of fault presence, magnitude of throw and suggests that fractured zones can be identified which may indicate higher permeability pathways within the reservoir. Another important learning from this case study is to use an integrated approach during processing and interpretation and donโt look only at one single part, e.g. velocity cube. Overall the results of this carbonate Azimuthal Pilot for fault and fracture characterization has produced encouraging results and valuable lessons learned to aid future studies.
- Research Report > New Finding (0.54)
- Research Report > Experimental Study (0.54)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.69)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (0.47)
Comparison of Traditional and Digital Rock Physics Techniques to Determine the Elastic Core Parameters in Cretaceous Formations, Abu Dhabi
Derzhi, Naum (Ingrain) | Dvorkin, Jack (Ingrain and Stanford University) | Diaz, Elizabeth (Ingrain) | Baldwin, Chuck (Ingrain) | Fang, Qian (Ingrain) | Sulayman, Ayoola (Ingrain) | Soroka, William L. (ExxonMobil) | Clark, Andrew (ADCO) | Al Dayyani, Taha (ADCO) | Kalam, Zubair (ADCO)
Abstract Knowledge of the elastic properties of rock, such as Vp, Vs, and Poissonโs ratio, is required input to accurate and rigorous reservoir description. Traditionally, these values had been acquired from log data or direct measurement in a physical laboratory. Recent advances in imaging and image processing, together with improved availability of high performance computing, gave rise to digital techniques for investigating the properties of rock samples. These techniques are based on high-resolution imaging of the rockโs pore space, segmentation of the images into pores and various minerals and simulation of the physical processes controlled by the desired rock properties. These techniques form the novel discipline of digital rock physics (DRP). The goal of the current work is to validate the results of DRP measurements of elastic parameters by comparing them with the results obtained in traditional physical laboratories. This study includes eight core plugs from a Cretaceous formation, representing four reservoir rock types. Multiple sub-samples of each core plug were taken and analyzed using the digital rock physics technique. Our DRP computations are compared with the results of physical measurements of the elastic properties on samples from Cretaceous formations under various stress conditions. The latter measurements were conducted on regular core plugs, several cm in size, much larger than the digital rock samples used in this study. Although some of the physical data represent samples from wells different from where the digital samples used here were extracted, these physical samples cover the rock types included in the study. The elastic property values obtained in the digital rock physics laboratory closely match the results of physical measurements conducted at effective stress about 30 MPa. This validation of elastic measurements using DRP ensures quick and reliable data acquisition, at significantly lower costs.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
3D VSP technology now a standard high-resolution reservoir-imaging technique: Part 2, interpretation and value
Mรผller, Klaus W. (Abu Dhabi Company for Onshore Oil Operations) | Soroka, William L. (Abu Dhabi Company for Onshore Oil Operations) | Paulsson, Bjรถrn (Abu Dhabi Company for Onshore Oil Operations) | Marmash, Samer (Abu Dhabi Company for Onshore Oil Operations) | Al Baloushi, Mariam (Abu Dhabi Company for Onshore Oil Operations) | Al Jeelani, Omar (Abu Dhabi Company for Onshore Oil Operations)
This second part of an article about a large 3D VSP survey in Abu Dhabi describes the interpretation effort which quantifies the value that a 3D VSP seismic image can bring when supplementing even a 640-fold, high-resolution surface seismic volume.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Near-well and vertical seismic profiles (1.00)
Abu Dhabi Company for Onshore Oil Operations (ADCO) undertook a two-well 3D VSP pilot project in 2007. Because it was acquired concurrently with a high-resolution wide-azimuth surface seismic survey, it was at the time the largest 3D VSP ever recorded. The project consisted of four main parts: acquisition, processing, interpretation, and quantifying value. In part 1 of this paper the acquisition and processing of the 3D VSP is described with an emphasis on the lessons learned. Significant advances in processing are described that demonstrate how larger 3D VSP images with better amplitudes and structural preservation can be produced. In part 2, the results of the 3D VSP interpretation and economic evaluation effort are described and illustrate different ways that a VSP image can help characterize a hydrocarbon reservoir.
Fluid Discrimination Applying AVA Potentiality for Carbonate Reservoir in UAE
Mahmoud, Sabry Lotfy (Abu Dhabi Co. Onshore Oil Opn.) | Othman, Adel (Al Azhar University) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.) | Al Jeelani, Abubaker Habib (Abu Dhabi Co. Onshore Oil Opn.) | Kamel, Diaa Al Deen (Al Azhar University)
Abstract Well based modeling and seismic data analysis were used to investigate the potential of Amplitude Variation with Angle (AVA) for fluid discrimination in a high porosity carbonate reservoir in a producing UAE oil field. Gassmann fluid substitution was used to model well log data, which included compressional and shear sonic logs and density logs to produce synthetic well logs representing the reservoir at 100% fluid saturations of brine, oil and gas at reservoir pressure and temperature conditions. The average VP/VS ratio for brine saturated reservoir (~2.0) was observed to be higher than both the oil (~1.7) and gas (~1.6) saturated reservoir cases. The modeled brine, oil and gas logs were used to calculate the AVA responses at the top and base of a thick, 25โ35 % porosity reservoir layer using the Zoeppritz equations. The responses for all three fluids were found to be a Class-IV type AVO anomaly. Seismic amplitude variation on the synthetic CDP gathers was successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data it can be possible to see a difference in AVA responses between brine and hydrocarbon filled porous reservoirs. An AVA study was performed using available relative amplitude CDP gathers along a 2D seismic line extracted from a 3D seismic volume. The results were able to discriminate between areas saturated with brine from those with hydrocarbon. The real seismic results were in good agreement with synthetic model results. The angle stack analysis was successful at improving the signal-to-noise ratio in lower fold seismic data and reduced the input data size requirement when dealing with larger CMP gathers. The effects of varying key reservoir and seismic properties on AVA response were examined to help understand the potential for misinterpretation. Introduction Seismic amplitude responses are affected by the types of rock present, the degree of consolidation, the saturating fluids plus rock properties such as porosity of the reservoir and the encasing layers. Gassmann fluid substitution is used to produce log data, which are representative of porous carbonate reservoirs filled with 100% brine, oil and gas. The fluid properties represent typical reservoir fluids under typical reservoir pressure and temperature conditions. The average VP/V S ratio for a brine saturated reservoir is approximately 2.0, for an oil saturated reservoir around 1.7 and for the gas saturated case around 1.6. Synthetic CMP gathers were created from the brine, oil and gas log data. The synthetic CMP gathers were put through an amplitude analysis at the top and base interfaces of the reservoir layer and found to be AVO class-IV anomaly and were successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data, it should be possible to see a difference in AVA response between brine and hydrocarbon filled porous reservoir. Modeling from the available well log data is used to calibrate the observed seismic AVA responses. AVA analysis was performed on real seismic along a 2D seismic line extracted from a 3D seismic volume over a carbonate reservoir in U.A.E. This case history over a known hydrocarbon occurance was used to confirm that different fluid types can be detect ed and agreed with the modeled results. The AVA responses were validated using the reservoir saturation information from the reservoir model and simulation modeling.
- Asia > Middle East > UAE (0.47)
- North America > United States > Kentucky > Butler County (0.44)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Offset (AVO) (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Angle (AVA) (1.00)
Abstract Well based modeling and seismic data analysis were used to investigate the potential of Amplitude Variation with Angle (AVA) for fluid discrimination in a high porosity carbonate reservoir in a producing UAE oil field. Gassmann fluid substitution was used to model well log data, which included compressional and shear sonic logs and density logs to produce synthetic well logs representing the reservoir at 100% fluid saturations of brine, oil and gas at reservoir pressure and temperature conditions. The average VP/VS ratio for brine saturated reservoir (~2.0) was observed to be higher than both the oil (~1.7) and gas (~1.6) saturated reservoir cases. The modeled brine, oil and gas logs were used to calculate the AVA responses at the top and base of a thick, 25โ35 % porosity reservoir layer using the Zoeppritz equations. The responses for all three fluids were found to be a Class-IV type AVO anomaly. Seismic amplitude variation on the synthetic CDP gathers was successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data it can be possible to see a difference in AVA responses between brine and hydrocarbon filled porous reservoirs. An AVA study was performed using available relative amplitude CDP gathers along a 2D seismic line extracted from a 3D seismic volume. The results were able to discriminate between areas saturated with brine from those with hydrocarbon. The real seismic results were in good agreement with synthetic model results. The angle stack analysis was successful at improving the signal-to-noise ratio in lower fold seismic data and reduced the input data size requirement when dealing with larger CMP gathers. The effects of varying key reservoir and seismic properties on AVA response were examined to help understand the potential for misinterpretation. Introduction Seismic amplitude responses are affected by the type of rocks present, the degree of consolidation, the saturating fluids plus rock properties such as porosity of the reservoir and the encasing layers. Gassmann fluid substitution is used to produce log data, which are representative of porous carbonate reservoirs filled with 100% brine, oil and gas. The fluid properties represent typical reservoir fluids under typical reservoir pressure and temperature conditions. The average VP/VS ratio for a brine saturated reservoir is approximately 2.0, for an oil saturated reservoir around 1.7 and for the gas saturated case around 1.6. Synthetic CMP gathers were created from the brine, oil and gas log data. The synthetic CMP gathers were put through an amplitude analysis at the top and base interfaces of the reservoir layer and found to be AVO class-IV anomaly and were successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging results on synthetic data suggest that with good quality seismic data, it should be possible to see a difference in AVA response between brine and hydrocarbon filled porous reservoir. Modeling from the available well log data is used to calibrate the observed seismic AVA responses. AVA analysis was performed on real seismic along a 2D seismic line extracted from a 3D seismic volume over a carbonate reservoir in U.A.E. This case history over a known hydrocarbon occurance was used to confirm that different fluid types can be detected and agreed with the modeled results. The AVA responses were validated using the reservoir saturation information from the reservoir model and simulation modeling.
- North America > United States > Kentucky > Butler County (0.44)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Offset (AVO) (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Angle (AVA) (1.00)
4D Seismic in Carbonates: From Rock Physics to Field Examples
Chen, Ganglin | Wrobel, Kelly (ExxonMobil Upstream Research Company) | Tiwari, Anupam (ExxonMobil Upstream Research Co.) | Zhang, Jie (ExxonMobil Upstream Research Company) | Payne, Michael (ExxonMobil Upstream Research Company) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.) | Hadidi, Mohamed T. (ADCO) | Sultan, Akmal Awais (Zakum Development Co.)
Abstract We have carried out 4D seismic research on two giant carbonate fields in Abu Dhabi, UAE, employing an integrated approach. Our work process started from fundamental rock physics analysis. The Xu-White rock physics model, originally designed for clastic rocks, was extended to carbonates. With this model, we characterized the reservoir interval by different (geophysical) pore types, related them to petrophysical (sedimentalogical) pore types, and performed log conditioning to improve well to seismic ties. Laboratory ultrasonic measurements of core plugs and log analysis were conducted in combination with the rock physics model to examine the fluid and pressure sensitivities. Results from rock physics analysis were used to build thickness variation (wedge) models and saturation variation models based on realistic reservoir conditions. Systematic synthetic seismic modeling was carried out. To compare with the field seismic data, we performed 3D synthetic seismic modeling, using horizons picked on the field seismic to define the input layering model. The rock properties of the reservoir layers were computed from saturation and pressure changes obtained from the reservoir simulation model using rock physics transforms. We refined the seismic processing sequence to enhance the 4D signals of the field seismic data. Our preliminary results show clear higher 4D seismic amplitude patterns in the crest of the structure. We will invert the data for seismic impedance to compare with the impedance volume from synthetic seismic modeling based on the reservoir simulation model. The results from 4D seismic will be used to update the reservoir and simulation models for optimal history match. Introduction Hydrocarbon production from carbonate fields constitutes a significant portion of total global energy supply. While 4D seismic data has been very successful in monitoring hydrocarbon production from clastic reservoirs (e.g., Gouveia et al., 2004; Calvert, 2005; Boutte, 2007), there is still no consensus on its applicability to carbonate fields. The main difficulty is the well-known fact that the acoustic velocities of carbonates are insensitive to saturation and pressure changes, relative to the clastics (e.g., Wang 2001). Figure 1 shows ultrasonic measurement data on two typical reservoir carbonate cores from one of the carbonate fields in Abu Dhabi, UAE. Figure 1a shows the pressure dependence of the compressional wave velocity of a dry sample. Under reservoir pressure conditions (3000 - 4000 psi), a pressure change of 500 psi changes the velocity by about 2%. In contrast, for unconsolidated sand-clay mixture samples of similar porosity (~20%) under similar pressure conditions, a change of 500 psi in the confining pressure induces about 6% change (three times of the carbonate sample) in the compressional wave velocity (Marion et al., 2001). The change in the P-wave velocity in the carbonate sample shown in Figure 1b is even more dismal until water saturation change reaches 90%.
- North America > United States (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.95)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Well Tie (1.00)
Intrinsic P- And S-wave Attenuation of Carbonate Reservoir Rocks From Seismic, Sonic, to Ultrasonic Frequencies
Chen, Ganglin (ExxonMobil Upstream Research Co.) | Chu, Dez (ExxonMobil Upstream Research Co.) | Zhang, Jie (ExxonMobil Upstream Research Co.) | Xu, Shiyu (ExxonMobil Upstream Research Co.) | Payne, Michael A. (ExxonMobil Upstream Research Co.) | Adam, Ludmila (Colorado School of Mines) | Soroka, William L. (ADCO)
Introduction Summary P-wave attenuation (1/Qp) and S-wave attenuation (1/Qs) are similar in each of the frequency bands(seismic, sonic, ultrasonic): 1/Qp ~ 1/Qs; The attenuation spectrum in each frequency band has an associated characteristic relaxation distance; For a given carbonate reservoir rock, attenuation in the ultrasonic frequency band can be ''anomalously'' high (Q~1) but still be โnormalโ (Q~10-100) in the seismic frequency band. New measurements of P- and S-wave velocity dispersion in carbonate reservoir rocks from seismic (<100Hz) to sonic (~10kHz) and ultrasonic (~1MHz) frequencies were analyzed to derive the frequency-domain intrinsic attenuation spectrum. Three rock samples were analyzed, all with porosity in the same range: one sample had high permeability and two had low permeability. We used the standard linear solid model to describe the twin relationship between velocity dispersion and attenuation. The analysis led to the following observations: One of the remaining highly debated subjects in seismic and rock physics is the variation in attenuation in fluidfilled reservoir rocks for seismic, sonic, and ultrasonic frequencies. This is an important issue in characterizing hydrocarbon reservoirs, because it provides the link between controlled laboratory measurements at ultrasonic frequencies and field measurements at seismic frequencies; this link would allow us to quantitatively interpret rock and fluid properties in the subsurface. Developing this relation is difficult, because measuring attenuation at seismic frequencies is challenging experimentally and results in significant uncertainties. For example, laboratory measurements at seismic frequencies of non-gas fluid filled reservoir rocks have reportedly produced Q values as low as 10 or even lower; such low Q values are not supported by field seismic data: Q values of this magnitude would ''wipe out'' any seismic reflection beneath an oil reservoir of medium thickness (10s of meters). It has long been recognized in the global seismology community that attenuative media produce dispersion (e.g., Futterman, 1962; Liu et al., 1976). The measured dispersion of moduli (or velocities) can be used to derive the frequency-domain attenuation spectrum. Experimental techniques for obtaining modulus by measuring stress and strain and for obtaining acoustic velocities in solid material are well established (e.g., suggested methods by ISRM ''International Society of Rock Mechanics - and standards by NIST'' National Institute of Standards and Technology). In general, uncertainties in modulus/velocity measurements are relatively low in well-calibrated experiments. In this study, new measurements of velocity dispersion in three carbonate reservoir rock samples were analyzed using standard linear viscoelastic solid models to determine the entire attenuation spectrum from seismic to sonic and ultrasonic frequencies. Method The data used in this study were from : laboratory measurements on three core plugs of carbonate reservoir rocks (Adam and Batzle, 2007); and sonic log data at the location where these core plugs were taken. Velocity dispersion was used to determine attenuation by fitting the measurements to a series of standard linear solid models (Figure 1)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.70)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.54)
Challenges of Seismic Processing of Transition-Zone Data: Comparison of Three State-of-the-Art Approaches
Hadidi, Mohamed T. (ADCO) | Nehaid, Hani Abdulla | Abousetta, Abdulnaser Ali (Abu Dhabi Co. Onshore Oil Opn.) | Abdulsalam, Ashraf Yahia (ADCO) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.)
Abstract A program of 2D seismic lines was acquired in a transition zone in Abu Dhabi in early 2007. The objective was to firm up exploration concepts in the cretaceous, including subtle reefal buildups. Three data issues were of concern, namely, matching the different seismic sources and receivers, static corrections, and noise attenuation for improved signal-to-noise ratio. Because transition-zone acquisition entails dealing with a variety of environments, it was necessary to use two types of sources, namely air gun arrays and dynamite, and three types of receivers - marsh geophones, hydrophones, and dual sensor units. Matching of the resulting six source-receiver combinations was a key challenge. The dynamic and complex nature of transition zones, situated between land and marine environments, causes noise levels to be particularly high. Mitigation of seismic noise was the second processing challenge. Finally, the low-relief structures that were the targets in this area placed stringent demands on the static solutions. Coming up with an accurate static solution was the third processing challenge. This project provided a unique case study in transition-zone processing, because the data was sent for processing by three contractors. This was done to verify that optimum processing has been performed on the data to meet the interpretation objectives. This afforded a rare and unique opportunity to compare three state-of the-art approaches to transition-zone seismic processing. This paper presents comparisons of the final migrated images obtained using the three processing approaches. It also refers to further analysis carried out using well-to-seismic ties and acoustic impedance sections produced by post-stack inversion. We will conclude with the key lessons gained from this experience, which we hope will find application to other projects dealing with this particularly challenging problem. Introduction With the rapid urbanization and breathtaking development of Abu Dhabi., a decision was made to acquire eleven seismic 2D lines in a transition-zone along the Abu Dhabi coast. The locations of the eleven new seismic lines were selected to complement existing seismic data in the area. The goal was to aid in assessing the remaining hydrocarbon potential in the area before commencement of the planned development activities. The key potential reservoir in the area is associated with subtle reefal buildups of Cretaceous age. Seismic acquisition was conducted using two different seismic sources and three different seismic receivers. Seismic sources consisted of dynamite on land, and a shallow airgun array in water. Three types of seismic receivers were employed: geophones in land and marsh environments, hydrophones in relatively shallow water, and dual-sensor units in relatively deep water. Other acquisition parameters were: 160 nominal fold, 25m receiver spacing, and either 25m or 50m shot spacing. Because of environmental and cost constraints, seismic sources were deployed at relatively shallow depths resulting in reduced low-frequency content of the seismic data. It was obvious at the outset, or became quickly apparent, that the key issues in seismic processing of the data were matching of the different source and receiver pairs, obtaining a good statics solution, and attenuation of the relatively high level of noise on this transition-zone seismic data.
High-Resolution 3D VSP Processing - An Example From the Middle East
Chavarria, Andres (Seismic Reservoir 2020 Inc.) | Paulsson, Bjorn Nils Patrick (Seismic Reservoir 2020 Inc.) | Goertz, Alexander (Paulsson Geophysical Services, Inc.) | Karrenbach, Martin (Seismic Reservoir 2020 Inc.) | Mueller, Klaus W. (Abu Dhabi Co. Onshore Oil Opn.) | Marmash, Samer (Abu Dhabi Company for Onshore Oil Operations) | Al Baloushi, Mariam Nasser (Abu Dhabi Co. Onshore Oil Opn.) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.)
Abstract The 3D VSP method is being increasingly employed as a tool to produce high-resolution images for detailed reservoir characterization and to address reservoir challenges. These challenges include thin layer reservoirs, thief zones and stratigraphic features that affect recovery. The main challenges in processing VSP datasets are twofold: First to ensure that the high frequency and better vector fidelity is being used and carried through to the final image. This requires special care and appropriately adapted processing techniques to the smaller scale and high frequency contained in the VSP data. Second, is dealing with the unique geometry of a 3D VSP, which has laterally varying fold coverage and aperture that has to be accounted for in order to minimize any footprint on the final image. In this project VSP processing advances have been made using data from the largest 3D VSP recorded to date, which was acquired in an Abu Dhabi oil field. Different types of static corrections were tested and optimized to recover the high frequencies required for optimum event delineation. A combination of static corrections that takes full advantage of the 3D VSP geometry and includes surface seismic data results that helped achieve optimal coherency of events. A careful analysis of the irregular fold geometry resulted in good target imaging using a detailed illumination analysis. Such an analysis aids in the correct treatment of the high resolution events and helps to interpret their character along the area illuminated. This analysis provides critical information about the velocity model and the corresponding kinematics. The ability of VSP's to recover high frequencies is demonstrated in this processing flow, by showing the difference in resolution between new high resolution surface seismic and the final 3D VSP image. Introduction The availability of 3D VSP data has resulted in more detailed characterizations of the reservoir because of the high resolution given by the VSP data compared to surface seismic techniques. Its usage includes detailed stratigraphic analysis of thin and often deep targets that the surface seismic cannot adequately image. In addition the VSP technology has been used in areas within complex near surface environments or areas where there is limited surface access. The use of receivers within the well has led to seismic images in the vicinity of the well that have high resolution and high signal to noise ratio. More importantly receivers in the borehole environment have led to high frequency data because of shorter travel paths. In the VSP case less energy is attenuated as it only travels once through the near surface weathering layer or complex overburdens. The high frequency recorded by the borehole array (Figure 1) consequently results in smaller Fresnel zones at the target in the vicinity of the well, therefore enhancing its lateral characterization.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.35)
- Asia > Middle East > Kuwait > Jahra Governorate (0.24)