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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)
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)
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.
A Modeling Feasibility Study Indicates Seismic AVO has Potential to Discriminate between Brine and Hydrocarbon in a Middle East Carbonate Reservoir
Mahmoud, Sabry Lotfy (Abu Dhabi Co. Onshore Oil Opn.) | Othman, Adel (Al Azhar University) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.) | Romiro, Tony (ADCO) | Smith, Adrian (Hampson-Russell)
Abstract A seismic Amplitude Variation with Offset (AVO) feasibility study was successfully conducted to investigate the potential for fluid discrimination in a high porosity carbonate reservoir from a producing oil field in the Middle East. Gassmann fluid substitution was used to model the available 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 modeled brine, oil and gas logs were used to calculate the AVO responses at the top and base of the reservoir layer using the Zoeppritz equations. The responses for all three fluids were found to be a Class-4 type AVO. The AVO results on the synthetic CDP gathers suggests that brine can be discriminated from hydrocarbon. These encouraging AVO results on synthetic data suggest that with good quality seismic data it might be possible to see a difference in AVO response between brine and hydrocarbon filled porous reservoir. An AVO case study was performed using available relative amplitude CMP gathers along a 2D seismic line extracted from a 3D seismic volume. The effects of key reservoir properties on AVO response were examined to help establish interpretation guidelines and better understand the potential for misinterpretation. Introduction The goal of this study is to distinguish between the effects of hydrocarbon and water in carbonate reservoirs by analyzing the AVO in seismic data over onshore carbonates reservoirs. The 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 AVO analysis at the top and base interfaces of the reservoir layer to determine if the gathers with brine could be distinguished from those with hydrocarbon in the reservoir layer. The AVO results on the synthetic CMP gathers were found to be AVO class-4 anomaly and were successful at discriminating brine from hydrocarbon but could not differentiate oil from gas. These encouraging AVO results on synthetic data suggest that with good quality seismic data, it should be possible to see a difference in AVO response between brine and hydrocarbon filled porous reservoir. The AVO modeling from the available well log data is used to calibrate the observed seismic AVO responses. AVO analysis was performed on real seismic along a 2D seismic line extracted from a 3D seismic volume over a Middle East onshore field. This case history over a known hydrocarbon occurance was used to confirm that different fluid types can be detect and agreed with the modeled AVO attribute results. The AVO 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 (0.45)
Neural Net Prediction of Porosity from Seismic Successfully Used to Improve the Reservoir Model Away from Well Control
Al-Zaabi, Naema (Abu Dhabi Oil Co. Ltd.) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.) | Abousetta, Abdulnaser Ali (Abu Dhabi Co. Onshore Oil Opn.) | Kaya, Avni Serdar (Abu Dhabi Co. Onshore Oil Opn.)
Abstract To maximize recovery from carbonate reservoirs it is necessary to build models that include as much detail as possible about the variations in reservoir properties. Due to the heterogeneous nature of many carbonate rocks the standard techniques of building a porosity model by using well data alone can produce models that do not accurately represent the true subsurface geology. Seismic data is another source of information that can provide valuable details about the changes in porosity away from well control. An inversion was performed on a seismic volume over an Abu Dhabi field to generate an acoustic impedance model of the reservoir. Using the acoustic impedance, available well data and other seismic attributes a neural net project was performed to produce a porosity volume. The porosity volume was in agreement with porosity log data at the well locations and showed lateral porosity variations that could be used to update the porosity in the reservoir model. A porosity volume was also calculated from the inversion acoustic impedance results using a porosity to acoustic impedance relationship derived from the log data. The inversion porosity model was used as and additional control on the neural net porosity from seismic results and for validation. The porosity from the neural net project was transferred to the reservoir model building software and successfully used to validate and update the porosity in the reservoir model away from well control. The revised porosity model more accurately showed the affects of faults on porosity and porosity changes due to digenesis and facies changes. The added details and more accurate lateral variations in reservoir porosity obtained from seismic information has the potential to produce more accurate and reliable simulation models showing the dynamic behavior of the reservoir. Introduction Giant Middle East carbonate reservoirs contain heterogeneities in facies, porosity and permeability that can impact the ability to reliably model fluid dynamics to maximize oil recovery. Efforts to build models that include more reservoir details and more accurately describe how rock properties vary in the reservoir are turning to seismic data, for information between well control. Advanced geophysics technologies are capable of identifying fluid flow pathways, flow anisotropy and subsurface rock property variations. With successful demonstrations of the value of seismic information to update and constrain the reservoir model the use of seismic data will continue to grow. Seismic data has the advantage of being able to image the whole reservoir and can show where reservoir property changes occur away from well control. In this study several geophysics technologies were successfully used to extract reservoir porosity from seismic. The integrated team which included geophysicists, reservoir engineers and specialists worked together to integrate the porosity from seismic information with the well based reservoir model and build more detail into the new reservoir model.
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.36)
- Asia > Middle East > Kuwait > Jahra Governorate (0.24)
3D Multiple Attenuation in the F-XY Domain: A Case History from Abu Dhabi
Ben Maroof, Muneera Saleh (Abu Dhabi Co. Onshore Oil Opn.) | Al Nahhas, Mohamad Samir (Abu Dhabi Co. Onshore Oil Opn.) | Soroka, William L. (Abu Dhabi Co. Onshore Oil Opn.) | Leveque, Andre (CGG Veritas) | Spitz, Simon (CGG Integrated Studies)
Abstract Multiples are successfully removed from seismic data to increase the signal-to-noise ratio in a 3D land dataset acquired in Abu Dhabi. The process aims at removing in user specified spatial-temporal windows only that multiple energy (surface or inter-bed), interfering with particular primary seismic events. The anti-multiple is designed in the f-xy domain and applied prestack, on constant offset time migrated data volumes. Subtraction of the multiple events from the original seismic data is shown to produce an improved subsurface seismic image that is more suitable for interpretation and attribute analysis. The ability to remove multiple events without affecting the primary signal is a crucial issue in seismic processing, as spurious energy at a target level leads to suboptimal images and adds uncertainty to reservoir characterization. The state of the art in attenuating multiple arrivals involves a two steps process. First the multiples are predicted via a data driven technique. Then the predicted events are matched to the multiples actually present in the data and removed with some matching filter. The removal assumes that the kinematics of the multiple events are correctly derived and that the prediction locates them correctly in time and space. The technique applied on the Abu Dhabi dataset focuses on a particular family of reverberating events that invade the target area. This is a marked difference with respect to general techniques that try to predict the whole multiple wavefield. The technique requires the strong impedance contrast that generates the multiple (surface related or internal) to be reasonably flat. When this requirement is met the prediction of the multiple is simple and avoids all shortcomings of general techniques such as SRME with irregular acquisition geometries, poor signal to noise ratio or variable near surface effects. Moreover we believe that this requirement is often met in the Arabic Peninsula. Introduction The need for seismic processing to more effectively remove multiple energy noise while preserving at the same time the primary events is growing in important due to both structural interpretation and advance geophysical analyses that require higher quality seismic data. Multiples can corrupt the primary seismic events at the target and lead to incorrect seismic attributes and erroneous interpretations. Multiple attenuation as applied in this land seismic study was a two step process. In the first step the multiples, which include both surface and inter-bed related multiples are predicted using a data driven process that does not involve any prior information concerning the subsurface velocities. In the second step the predicted multiple events are matched to the multiple events present in the seismic data and removed using a derived matching filter. This approach assumes that the dominant multiple events in the zone of interest are correctly derived and that the prediction locates the multiples at their proper seismic time. The method is applied in a way that minimizes any possible interference between the primary seismic events and the multiples to preserve the primary seismic event amplitudes. Figure 1 compares a simple reflection, surface related multiple and interbed multiple to illustrate their differences. The seismic data used in this study has strong multiple energy that has similar moveout to the primary events and is difficult to remove without damaging the primaries. The multiple method used in this study did not require moveout differences between the primary and multiple events in order to be able to remove the multiples.
- Information Technology > Data Science (0.49)
- Information Technology > Artificial Intelligence (0.34)