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Mahgoub, Mohamed, Yasir Bashir, Andy Anderson Bery, and Abdelwahab Noufal. "Four-Dimension Seismic Analysis in Carbonate: A Closed Loop Study." Applied Sciences 12, no. 19 (September 21, 2022): 9438. http://dx.doi.org/10.3390/app12199438.
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Four-dimensional seismic analysis is an effective reservoir surveillance tool to track the changes of fluid and pressure phases in the oil and gas reservoirs over time of the baseline and monitoring seismic acquisition. In practice, the 4D seismic signal associated with such changes may be negligible, especially in heterogeneous carbonate reservoirs. Therefore, 4D seismic analysis is a model for integrating various disciplines in the oil and gas industry, such as seismic, petrophysics, reservoir engineering, and production engineering. In this study, we started the 4D seismic workflow with a 1D well-based 4D feasibility study to detect the likelihood of 4D signals before performing 4D seismic co-processing of the baseline and monitoring surveys starting from the seismic field data of both datasets. As part of a full 4D seismic co-processing of the baseline and monitor surveys, 4D seismic metric attributes were analyzed over the survey area to measure the improvement in seismic acquisition repeatability for the scarce 1994 baseline seismic and the 2014 monitor seismic survey. For the monitor survey, a 4D time-trace shift was performed using the baseline survey as a reference to measure the time shifts between the baseline and monitor surveys at 20-year intervals. The 4DFour-dimensional dynamic trace warping was followed by a 4D seismic inversion to compare the 4D difference in the seismic inverted data with the difference in seismic amplitude. The seismic inversion helped overcome noise, multiple contaminations, and differences in dynamic amplitude range between the baseline and monitor seismic surveys. We then examined the relationship between well logs and seismic volumes by predicting a volume of log properties at the well locations of the seismic volume. In this method, we computed a possibly nonlinear operator that can predict well logs based on the properties of adjacent seismic data. We then tested a Deep Feed Forward Neural Network (DFNN) on six wells to adequately train and validate the machine learning approach using the baseline and monitoring seismic inverted data. The objective of trying such a deep machine learning approach was to predict the density and porosity of both the baseline and the monitoring seismic data to validate the accuracy of the 4D seismic inversion and evaluate the changes in reservoir properties over a time-lapse of 20 years of production from 1994 to 2014. Finally, we matched the 4D seismic signal with changes in reservoir production properties, investigating the mechanism underlying the observed 4D signal. It was found that the detectability of 4D signals is primarily related to changes in fluid saturation and pressure changes in the reservoir, which increased from 1994 to 2014. This innovative closed-loop research proved that the low repeatability of seismic acquisition can be compensated by optimal 4D seismic co-processing with a complete integration workflow to assess the reliability of the 4D seismic observed signal.
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Romero, Juan, Nick Luiken, and Matteo Ravasi. "Seeing through the CO2 plume: Joint inversion-segmentation of the Sleipner 4D seismic data set." Leading Edge 42, no. 7 (July 2023): 457–64. http://dx.doi.org/10.1190/tle42070457.1.
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Time-lapse (4D) seismic inversion is the leading method to quantitatively monitor fluid-flow dynamics in the subsurface, with applications ranging from enhanced oil recovery to subsurface CO2 storage. The process of inverting 4D seismic data for reservoir properties is a notoriously ill-posed inverse problem due to the band-limited and noisy nature of seismic data and inaccuracies in the repeatability of 4D acquisition surveys. Consequently, ad-hoc regularization strategies are essential for the 4D seismic inverse problem to obtain geologically meaningful subsurface models and associated 4D changes. Motivated by recent advances in the field of convex optimization, we propose a joint inversion-segmentation algorithm for 4D seismic inversion that integrates total variation and segmentation priors as a way to counteract missing frequencies and present noise in 4D seismic data. The proposed inversion framework is designed for poststack seismic data and applied to a pair of seismic volumes from the open Sleipner 4D seismic data set. Our method has three main advantages over state-of-the-art least-squares inversion methods. First, it produces high-resolution baseline and monitor acoustic models. Second, it mitigates nonrepeatable noise and better highlights real 4D changes by leveraging similarities between multiple data. Finally, it provides a volumetric classification of the acoustic impedance 4D difference model (4D changes) based on user-defined classes (i.e., percentages of speedup or slowdown in the subsurface). Such advantages may enable more robust stratigraphic/structural and quantitative 4D seismic interpretation and provide more accurate inputs for dynamic reservoir simulations. Alongside presenting our novel inversion method, we introduce a streamlined data preprocessing sequence for the 4D Sleipner poststack seismic data set that includes time-shift estimation and well-to-seismic tie. Finally, we provide insights into the open-source framework for large-scale optimization that we used to implement the proposed algorithm in an efficient and scalable manner.
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Skorstad, Arne, Odd Kolbjornsen, Asmund Drottning, Havar Gjoystdal, and Olaf K. Huseby. "Combining Saturation Changes and 4D Seismic for Updating Reservoir Characterizations." SPE Reservoir Evaluation & Engineering 9, no. 05 (October 1, 2006): 502–12. http://dx.doi.org/10.2118/106366-pa.
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Summary Elastic seismic inversion is a tool frequently used in analysis of seismic data. Elastic inversion relies on a simplified seismic model and generally produces 3D cubes for compressional-wave velocity, shear-wave velocity, and density. By applying rock-physics theory, such volumes may be interpreted in terms of lithology and fluid properties. Understanding the robustness of forward and inverse techniques is important when deciding the amount of information carried by seismic data. This paper suggests a simple method to update a reservoir characterization by comparing 4D-seismic data with flow simulations on an existing characterization conditioned on the base-survey data. The ability to use results from a 4D-seismic survey in reservoir characterization depends on several aspects. To investigate this, a loop that performs independent forward seismic modeling and elastic inversion at two time stages has been established. In the workflow, a synthetic reservoir is generated from which data are extracted. The task is to reconstruct the reservoir on the basis of these data. By working on a realistic synthetic reservoir, full knowledge of the reservoir characteristics is achieved. This makes the evaluation of the questions regarding the fundamental dependency between the seismic and petrophysical domains stronger. The synthetic reservoir is an ideal case, where properties are known to an accuracy never achieved in an applied situation. It can therefore be used to investigate the theoretical limitations of the information content in the seismic data. The deviations in water and oil production between the reference and predicted reservoir were significantly decreased by use of 4D-seismic data in addition to the 3D inverted elastic parameters. Introduction It is well known that the information in seismic data is limited by the bandwidth of the seismic signal. 4D seismics give information on the changes between base and monitor surveys and are consequently an important source of information regarding the principal flow in a reservoir. Because of its limited resolution, the presence of a thin thief zone can be observed only as a consequence of flow, and the exact location will not be found directly. This paper addresses the question of how much information there is in the seismic data, and how this information can be used to update the model for petrophysical reservoir parameters. Several methods for incorporating 4D-seismic data in the reservoir-characterization workflow for improving history matching have been proposed earlier. The 4D-seismic data and the corresponding production data are not on the same scale, but they need to be combined. Huang et al. (1997) proposed a simulated annealing method for conditioning these data, while Lumley and Behrens (1997) describe a workflow loop in which the 4D-seismic data are compared with those computed from the reservoir model. Gosselin et al. (2003) give a short overview of the use of 4D-seismic data in reservoir characterization and propose using gradient-based methods for history matching the reservoir model on seismic and production data. Vasco et al. (2004) show that 4D data contain information of large-scale reservoir-permeability variations, and they illustrate this in a Gulf of Mexico example.
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Lumley, D. E., and R. A. Behrens. "Practical Issues of 4D Seismic Reservoir Monitoring: What an Engineer Needs to Know." SPE Reservoir Evaluation & Engineering 1, no. 06 (December 1, 1998): 528–38. http://dx.doi.org/10.2118/53004-pa.
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Summary Time-lapse three-dimensional (3D) seismic, which geophysicists often abbreviate to four-dimensional (4D) seismic, has the ability to image fluid flow in the interwell volume by repeating a series of 3D seismic surveys over time. Four-dimensional seismic shows great potential in reservoir monitoring and management for mapping bypassed oil, monitoring fluid contacts and injection fronts, identifying pressure compartmentalization, and characterizing the fluid-flow properties of faults. However, many practical issues can complicate the simple underlying concept of a 4D project. We address these practical issues from the perspective of a reservoir engineer on an asset team by asking a series of practical questions and discussing them with examples from several of Chevron's ongoing 4D projects. We discuss feasibility tests, technical risks, and the cost of doing 4D seismic. A 4D project must pass three critical tests to be successful in a particular reservoir: Is the reservoir rock highly compressible and porous? Is there a large compressibility contrast and sufficient saturation changes over time between the monitored fluids? and Is it possible to obtain high-quality 3D seismic data in the area with clear reservoir images and highly repeatable seismic acquisition? The risks associated with a 4D seismic project include false anomalies caused by artifacts of time-lapse seismic acquisition and processing and the ambiguity of seismic interpretation in trying to relate time-lapse changes in seismic data to changes in saturation, pressure, temperature, or rock properties. The cost of 4D seismic can be viewed as a surcharge on anticipated well work and expressed as a cost ratio (seismic/wells), which our analysis shows ranges from 5 to 35% on land, 10 to 50% on marine shelf properties, and 5 to 10% in deepwater fields. Four-dimensional seismic is an emerging technology that holds great promise for reservoir management applications, but the significant practical issues involved can make or break any 4D project and need to be carefully considered. Introduction Four-dimensional seismic reservoir monitoring is the process of repeating a series of 3D seismic surveys over a producing reservoir in time-lapse mode. It has a potentially huge impact in reservoir management because it is the first technique that may allow engineers to image dynamic reservoir processes1 such as fluid movement,2 pressure build-up,3 and heat flow4,5 in a reservoir in a true volumetric sense. However, we demonstrate that practical operational issues easily can complicate the simple underlying concept. These issues include requiring the right mix of business drivers, a favorable technical risk assessment and feasibility study, a highly repeatable seismic acquisition survey design, careful high-resolution amplitude-preserved seismic data processing, and an ultimate reconciliation of 4D seismic images with independent reservoir borehole data and history-matched flow simulations. The practical issues associated with 4D seismic suggest that it is not a panacea. Four-dimensional seismic is an exciting new emerging technology that requires careful analysis and integration with traditional engineering data and workflows to be successful. Our objective in this paper is to provide an overview of the 4D seismic method and illuminate the practical issues important to an asset team reservoir engineer. For this reason, we do not present a comprehensive case study of a single 4D project here, but instead draw examples from several Chevron 4D projects to illustrate each of our points. We have structured this paper as a series of questions an engineer should ask before undertaking any 4D seismic project: What is 4D seismic? What can 4D seismic do for me? Will 4D seismic work in my reservoir? What are the risks with 4D seismic? What does 4D seismic cost? We answer these questions, highlight important issues, and offer lessons learned, rules of thumb, and general words of advice. What Is 4D Seismic? To describe the basic concepts underlying 4D seismic, we briefly review the seismic method in general6 and then consider the advantages of the time-lapse aspect of 4D seismic. In a single 3D seismic survey, seismic sources (dynamite, airguns, vibrators, etc.) generate seismic waves at or near the earth's surface. These source waves reflect off subsurface seismic impedance contrasts that are a function of rock and fluid compressibility, shear modulus, and bulk density. Arrays of receivers (geophones or hydrophones) record the reflected seismic waves as they arrive back at the earth's surface. Applying a wave-equation-imaging algorithm7 to the recorded wavefield creates a 3D seismic image of the reservoir rock and fluid property contrasts that are responsible for the reflections. Four-dimensional seismic analysis involves simply repeating the 3D seismic surveys, such that the fourth dimension is calendar time,8 to construct and compare seismic images in time-lapse mode to monitor time-varying processes in the subsurface during reservoir production. The term 4D seismic is usually reserved for time-lapse 3D seismic, as opposed to other time-lapse seismic techniques that do not have 3D volumetric coverage [e.g., two dimensional (2D) surface seismic, and the borehole seismic methods of vertical seismic profiling and crosswell seismic9,10]. Four-dimensional seismic has all the traditional reservoir characterization benefits of 3D seismic,11 plus the major additional benefit that fluid-flow features may be imaged directly. To first order, seismic images are sensitive to spatial contrasts in two distinct types of reservoir properties: time-invariant static geology properties such as lithology, porosity, and shale content; and time-varying dynamic fluid-flow properties such as fluid saturation, pore pressure, and temperature. Fig. 1 shows how the seismic impedance of rock samples with varying porosity changes as the pore saturation changes from oil-full to water-swept conditions. Given a single 3D seismic survey, representing a single snapshot in time of the reservoir, the static geology and dynamic fluid-flow contributions to the seismic image couple nonuniquely and are, therefore, difficult to separate unambiguously. For example, it may be impossible to distinguish a fluid contact from a lithologic boundary in a single seismic image, as shown in Frames 1 and 2 of Fig. 2. Examining the difference between time-lapse 3D seismic images (i.e., 4D seismic) allows the time-invariant geologic contributions to cancel, resulting in a direct image of the time-varying changes caused by reservoir fluid flow (Frame 3 of Fig. 2). In this way, the 4D seismic technique has the potential to image reservoir scale changes in fluid saturation, pore pressure, and temperature during production.
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Oliver, Dean S., Kristian Fossum, Tuhin Bhakta, Ivar Sandø, Geir Nævdal, and Rolf Johan Lorentzen. "4D seismic history matching." Journal of Petroleum Science and Engineering 207 (December 2021): 109119. http://dx.doi.org/10.1016/j.petrol.2021.109119.
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Amoyedo, Sunday, Emmanuel Ekut, Rasaki Salami, Liliana Goncalves-Ferreira, and Pascal Desegaulx. "Time-Lapse Seismic for Reservoir Management: Case Studies From Offshore Niger Delta, Nigeria." SPE Reservoir Evaluation & Engineering 19, no. 03 (April 5, 2016): 391–402. http://dx.doi.org/10.2118/170808-pa.
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Summary This paper presents case studies focused on the interpretation and integration of seismic reservoir monitoring from several fields in conventional offshore and deepwater Niger Delta. The fields are characterized by different geological settings and development-maturity stages. We show different applications varying from qualitative to quantitative use of time-lapse (4D) seismic information. In the first case study, which is in shallow water, the field has specific reservoir-development challenges, simple geology, and is in phased development. On this field, 4D seismic, which was acquired several years ago, is characterized by poor seismic repeatability. Nevertheless, we show that because of improvements from seismic reprocessing, 4D seismic makes qualitative contributions to the ongoing field development. In the second case study, the field is characterized by complex geological settings. The 4D seismic is affected by overburden with strong lateral variations in velocity and steeply dipping structure (up to 40°). Prestack-depth-imaging (PSDM) 4D seismic is used in a more-qualitative manner to monitor gas injection, validate the geologic/reservoir models, optimize infill injector placement, and consequently, enhance field-development economics. The third case study presents a deep offshore field characterized by a complex depositional system for some reservoirs. In this example, good 4D-seismic repeatability (sum of source- and receiver-placement differences between surveys, dS+dR) is achieved, leading to an increased quantitative use of 4D monitoring for the assessment of sand/sand communication, mapping of oil/water (OWC) front, pressure evolution, and dynamic calibration of petro-elastic model (PEM), and also as a seismic-based production-logging tool. In addition, 4D seismic is used to update seismic interpretation, provide a better understanding of internal architecture of the reservoirs units, and, thereby, yield a more-robust reservoir model. The 4D seismic in this field is a key tool for field-development optimization and reservoir management. The last case study illustrates the need for seismic-feasibility studies to detect 4D responses related to production. In addition to assessing the impact of the field environment on the 4D- seismic signal, these studies also help in choosing the optimum seismic-survey type, design, and acquisition parameters. These studies would possibly lead to the adoption of new technologies such as broad-band streamer or nodes acquisition in the near future.
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Rappin, Didier, and Phuong-Thu Trinh. "4D petroelastic model calibration using time-lapse seismic signal." Leading Edge 41, no. 12 (December 2022): 824–31. http://dx.doi.org/10.1190/tle41120824.1.
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In the last two decades, 4D seismic monitoring has become a widely used technique for oil and gas field production. Modeling studies are a standard for defining reservoir monitoring plans, optimizing survey design, and justifying the expense of data acquisition. Discrepancies between 4D seismic data and synthetic results can be analyzed through petroelastic modeling of reservoir simulations. However, assuming that a history match is available and that the reservoir model and fluid-flow simulation results can be trusted, characterization of pressure and fluid changes in the field remain challenging. A workflow is proposed to adjust the 4D petroelastic model (PEM) to better fit 4D seismic attributes with the dynamic behavior of the reservoir. The input data for 4D inversion consist of multiple broadband 4D-compliant processed base and monitor surveys recorded in a highly depleted clastic field offshore Africa. The broadband inversion results greatly reduce the background noise level, enhance the signal-to-noise ratio, and improve the definition of 4D signals. Due to various production effects all over the field, a new global calibration workflow to speed up the 4D petroelastic model adjustment is proposed. The combination of good 4D seismic inversions and a well-calibrated PEM is expected to have a significant impact on the reservoir monitoring. During the calibration process, reservoir model discrepancies with 4D seismic attributes can be identified, suggesting some updates of the reservoir model. In addition, when further monitors are considered, the calibrated 4D PEM provides more reliable predictability.
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Cruz, Nathalia Martinho, José Marcelo Cruz, Leonardo Márcio Teixeira, Mônica Muzzette da Costa, Laryssa Beatriz de Oliveira, Eduardo Naomitsu Urasaki, Thais Pontes Bispo, Manoel de Sá Jardim, Marcos Hexsel Grochau, and Alexandre Maul. "Tupi Nodes pilot: A successful 4D seismic case for Brazilian presalt reservoirs." Leading Edge 40, no. 12 (December 2021): 886–96. http://dx.doi.org/10.1190/tle40120886.1.
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The oil and gas industry has established 4D seismic as a key tool to maximize oil recovery and operational safety in siliciclastic and low- to medium-stiffness carbonate reservoirs. However, for the stiffer carbonate reservoirs of the Brazilian presalt, the value of 4D seismic is still under debate. Tupi Field has been the stage of a pioneering 4D seismic project to field test the time-lapse technique's ability in monitoring production and water-alternating-gas (WAG) injection in the Brazilian presalt. Ocean-bottom node (OBN) technology was applied for the first time in the ultra-deep waters of Santos Basin, leading to the Tupi Nodes pilot project. We started with feasibility studies to forecast the presalt carbonate time-lapse responses. The minerals that constitute these carbonate rocks have an incompressibility modulus that is generally twice as large as those of siliciclastic rocks. This translates into discrete 4D signals that require enhanced seismic acquisition and processing techniques to be correctly detected and mapped. Consequently, two OBN seismic acquisitions were carried out. Time-lapse processing included the application of top-of-the-line processing tools, such as interbed multiple attenuation. The resulting 4D amplitude images demonstrate good signal-to-noise ratio, supporting both static and dynamic interpretations that are compatible with injection and production histories. To unlock the potential of 4D quantitative interpretation and the future employment of 4D-assisted history-matching workflows, we conducted a 4D seismic inversion test. Acoustic impedance variations of about 1.5% are reliably distinguishable beyond the immediate vicinity of the wells. These 4D OBN seismic surveys and interpretations will assist in identifying oil-bypassed targets for infill wells and calibrating WAG cycles, increasing oil recovery. We anticipate that studies of the entire Brazilian presalt section will greatly benefit from the results and conclusions already reached for Tupi Field.
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Maleki, Masoud, Shahram Danaei, Felipe Bruno Mesquita da Silva, Alessandra Davolio, and Denis José Schiozer. "Stepwise uncertainty reduction in time-lapse seismic interpretation using multi-attribute analysis." Petroleum Geoscience 27, no. 3 (February 25, 2021): petgeo2020–087. http://dx.doi.org/10.1144/petgeo2020-087.
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Recently, time-lapse seismic (4D seismic) has been steadily used to demonstrate the relation between field depletion and 4D seismic response, and, subsequently, to provide more efficient field management. A key component of reservoir monitoring is the knowledge of fluid movement and pressure variation. This information is vital in assisting infill drilling and as a reliable source of data to update reservoir models, and, consequently, in helping to improve model-based reservoir management and decision-making processes. However, in practice, varying levels of uncertainty are inherent in the 4D seismic interpretation of reservoirs that uses a multipart production regime. The complex nature of some 4D seismic signals emphasizes the role of the competing effects of geology, rock and fluid interactions. Hence, a reliable 4D interpretation requires an interdisciplinary approach that entails data analysis and insights from geophysics, engineering and geology. In this study, a stepwise workflow was introduced to reduce the uncertainties in the 4D seismic interpretation and to identify the improvements required in order to perform better reservoir surveillance. In parallel, the workflow demonstrates the use of engineering data analysis in conducting a consistent interpretation, and encompasses the 3D and 4D seismic attributes with engineering data analysis. This study was carried out in a Brazilian heavy-oil offshore field where production started in 2013. The field experienced intense production activity up to 2016, making the deep-water field an ideal candidate to explore the challenges in interpreting complex 4D signals. Beyond these challenges, a significant understanding of reservoir behaviour is obtained and improvements to the reservoir simulation model are suggested that could assist reservoir engineers with data assimilation applications.
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Brice, Tim, Leif Larsen, Steve Morice, and Morten Svendsun. "Perturbations in 4D marine seismic." ASEG Extended Abstracts 2001, no. 1 (December 2001): 1–4. http://dx.doi.org/10.1071/aseg2001ab010.
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Landro, Martin, Odd Arve Solheim, Eilert Hilde, Bjorn Olav Ekren, and Lars Kristian Stronen. "The Gullfaks 4D seismic study." Petroleum Geoscience 5, no. 3 (August 1999): 213–26. http://dx.doi.org/10.1144/petgeo.5.3.213.
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Parker, John, Luca Bertelli, and Peter Dromgoole. "4D Seismic Technology Special Issue." Petroleum Geoscience 9, no. 1 (January 2003): iv. http://dx.doi.org/10.1144/1354-079302-for.
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Rosa, Daiane R., Juliana M. C. Santos, Rafael M. Souza, Dario Grana, Denis J. Schiozer, Alessandra Davolio, and Yanghua Wang. "Comparing different approaches of time-lapse seismic inversion." Journal of Geophysics and Engineering 17, no. 6 (November 4, 2020): 929–39. http://dx.doi.org/10.1093/jge/gxaa053.
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Abstract Time-lapse (4D) seismic inversion aims to predict changes in elastic rock properties, such as acoustic impedance, from measured seismic amplitude variations due to hydrocarbon production. Possible approaches for 4D seismic inversion include two classes of method: sequential independent 3D inversions and joint inversion of 4D seismic differences. We compare the standard deterministic methods, such as coloured and model-based inversions, and the probabilistic inversion techniques based on a Bayesian approach. The goal is to compare the sequential independent 3D seismic inversions and the joint 4D inversion using the same type of algorithm (Bayesian method) and to benchmark the results to commonly applied algorithms in time-lapse studies. The model property of interest is the ratio of the acoustic impedances, estimated for the monitor, and base surveys at each location in the model. We apply the methods to a synthetic dataset generated based on the Namorado field (offshore southeast Brazil). Using this controlled dataset, we can evaluate properly the results as the true solution is known. The results show that the Bayesian 4D joint inversion, based on the amplitude difference between seismic surveys, provides more accurate results than sequential independent 3D inversion approaches, and these results are consistent with deterministic methods. The Bayesian 4D joint inversion is relatively easy to apply and provides a confidence interval of the predictions.
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Kazemi, Alireza, Karl D. Stephen, and Asghar Shams. "Seismic History Matching of Nelson Using Time-Lapse Seismic Data: An Investigation of 4D Signature Normalization." SPE Reservoir Evaluation & Engineering 14, no. 05 (September 21, 2011): 621–33. http://dx.doi.org/10.2118/131538-pa.
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Summary History matching of a reservoir model is always a difficult task. In some fields, we can use time-lapse (4D) seismic data to detect production-induced changes as a complement to more conventional production data. In seismic history matching, we predict these data and compare to observations. Observed time-lapse data often consist of relative measures of change, which require normalization. We investigate different normalization approaches, based on predicted 4D data, and assess their impact on history matching. We apply the approach to the Nelson field in which four surveys are available over 9 years of production. We normalize the 4D signature in a number of ways. First, we use predictions of 4D signature from vertical wells that match production, and we derive a normalization function. As an alternative, we use crossplots of the full-field prediction against observation. Normalized observations are used in an automatic-history-matching process, in which the model is updated. We analyze the results of the two normalization approaches and compare against the case of just using production data. The result shows that when we use 4D data normalized to wells, we obtain 49% reduced misfit along with 36% improvement in predictions. Also over the whole reservoir, 8 and 7% reduction of misfits for 4D seismic are obtained in history and prediction periods, respectively. When we use only production data, the production history match is improved to a similar degree (45%), but in predictions, the improvement is only 25% and the 4D seismic misfit is 10% worse. Finding the unswept areas in the reservoir is always a challenge in reservoir management. By using 4D data in history matching, we can better predict reservoir behavior and identify regions of remaining oil.
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Brain, Jonathan, Thomas Lassaigne, Mathieu Darnet, and Peter Van Loevezijn. "Unlocking 4D seismic technology to maximize recovery from the pre-salt Rotliegend gas fields of the Southern North Sea." Geological Society, London, Petroleum Geology Conference series 8, no. 1 (July 3, 2017): 465–71. http://dx.doi.org/10.1144/pgc8.38.
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AbstractThe Southern North Sea is a mature gas basin, producing mainly from faulted Permian Rotliegend sandstones. Identifying infill well opportunities in un-depleted or partially depleted blocks in these fields is challenging, particularly if the sealing capacity of faults within a field is uncertain. Time-lapse (4D) seismic monitoring provides an opportunity to identify depleted reservoir blocks by measuring differences in travel time across the producing interval between seismic surveys acquired before and after gas production. 4D seismic field tests were initially performed by Nederlandse Aardolie Maatschappij (NAM) and Shell in 2001. However, the observed travel-time differences proved to be smaller than predicted and any possible signals were too noisy to confidently detect depletion. Since then, advances in seismic acquisition and processing technology have improved the accuracy of 4D measurements and enabled the effective mapping of 4D related gas depletion signals. 4D seismic has now been deployed over a number of fields in the Southern North Sea, and a portfolio of infill opportunities has been identified. In 2015, the first 4D targeted infill well was successfully drilled into a block with limited depletion. This technology represents a breakthrough for operators seeking to maximize hydrocarbon recovery and extend field life in the Rotliegend play of the Southern North Sea.
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Ketineni, Sarath Pavan, Subhash Kalla, Shauna Oppert, and Travis Billiter. "Quantitative Integration of 4D Seismic with Reservoir Simulation." SPE Journal 25, no. 04 (April 23, 2020): 2055–66. http://dx.doi.org/10.2118/191521-pa.
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Summary Standard history-matching workflows use qualitative 4D seismic observations to assist in reservoir modeling and simulation. However, such workflows lack a robust framework for quantitatively integrating 4D seismic interpretations. 4D seismic or time-lapse-seismic interpretations provide valuable interwell saturation and pressure information, and quantitatively integrating this interwell data can help to constrain simulation parameters and improve the reliability of production modeling. In this paper, we outline technologies aimed at leveraging the value of 4D for reducing uncertainty in the range of history-matched models and improving the production forecast. The proposed 4D assisted-history-match (4DAHM) workflows use interpretations of 4D seismic anomalies for improving the reservoir-simulation models. Design of experiments is initially used to generate the probabilistic history-match simulations by varying the range of uncertain parameters (Schmidt and Launsby 1989; Montgomery 2017). Saturation maps are extracted from the production-history-matched (PHM) simulations and then compared with 4D predicted swept anomalies. An automated extraction method was created and is used to reconcile spatial sampling differences between 4D data and simulation output. Interpreted 4D data are compared with simulation output, and the mismatch generated is used as a 4D filter to refine the suite of reservoir-simulation models. The selected models are used to identify reservoir-simulation parameters that are sensitive for generating a good match. The application of 4DAHM workflows has resulted in reduced uncertainty in volumetric predictions of oil fields, probabilistic saturation S-curves at target locations, and fundamental changes to the dynamic model needed to improve the match to production data. Results from adopting this workflow in two different deepwater reservoirs are discussed. They not only resulted in reduced uncertainty, but also provided information on key performance indicators that are critical in obtaining a robust history match. In the first case study presented, the deepwater oilfield 4DAHM resulted in a reduction of uncertainty by 20% of original oil in place (OOIP) and by 25% in estimated ultimate recoverable (EUR) oil in the P90 to P10 range estimates. In the second case study, 4DAHM workflow exploited discrepancies between 4D seismic and simulation data to identify features necessary to be included in the dynamic model. Connectivity was increased through newly interpreted interchannel erosional contacts, as well as subseismic faults. Moreover, the workflow provided an improved drilling location, which has the higher probability of tapping unswept oil and better EUR. The 4D filters constrained the suite of reservoir-simulation models and helped to identify four of 24 simulation parameters critical for success. The updated PHM models honor both the production data and 4D interpretations, resulting in reduced uncertainty across the S-curve and, in this case, an increased P50 OOIP of 24% for a proposed infill drilling location, plus a significant cycle-time savings.
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Waggoner, J. R. "Quantifying the Economic Impact of 4D Seismic Projects." SPE Reservoir Evaluation & Engineering 5, no. 02 (April 1, 2002): 111–15. http://dx.doi.org/10.2118/77969-pa.
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Summary Time-lapse 3D, or 4D, seismic imaging has been analyzed by the industry for more than a decade, with a growing number of successful cases being reported in the literature. Two of the most recent 4D case studies1 reporting success are Draugen in the Norwegian North Sea and Gannet-C on the U.K. continental shelf. Both have been technical successes, providing good images of time-lapse changes in the reservoir. These 4D results have changed drilling locations and reduced the risk associated with costly field development decisions. (Note: from this point forward, "4D" is used to refer to time-lapse seismic imaging.) The focus of this paper is quantifying the economic impact of 4D. After reviewing some ways that 4D can impact reservoir management, an economic model is developed that can quantify that impact. The decision tree model uses Bayes' theorem to compute the modified probabilities resulting from 4D. The model indicates that, for the case of drilling an infill well, 4D information adds considerable value to the project, even considering that the 4D information is not perfect. Introduction Time-lapse 3D, or 4D, seismic imaging has been reported as "successful" in several recent publications,1-3 but what does "successful"a actually mean? One definition can be that a 4D seismic difference image was calculated and validated with known reservoir conditions at the wells. Such a result would be a technical success because the reservoir change generated a seismic difference that was strong enough to be observed above the seismic repeatability noise.4 But did the 4D result impact the management of the reservoir? If not, the 4D project would have been largely an academic exercise, and it would be hard to justify the cost of the project. But, if the 4D results were used to impact reservoir management (e.g., by helping to make or change reservoir development or production decisions), the 4D project could also be termed a business success.5 But did the improved reservoir management generate more revenue for the company than the 4D project cost the company? If not, one would have to question, as the accountants surely will, whether the company actually benefited from the 4D project. However, if the revenue exceeded the cost, then the project would also be considered an economic success. This line of reasoning suggests that the ultimate success of a 4D project is at least as dependent on reservoir management and economic issues as it is on technical issues. Further, projects are increasingly expected not only to be economic successes, but also to quantify the likely economic impact before project funding is approved. Therefore, it is important to know how to quantify the predicted economic impact of 4D projects. However, before quantifying an economic impact, the reservoir management impact must be quantified. For example, a commonly stated impact of 4D is saving the cost of a well, for which an economic benefit is fairly easy to quantify as the cost of the well. However, another impact could be to confirm assumptions about the presence and sealing characteristics of faults. But, if nothing changes, has there been an impact? Perhaps, if the confirmation reduces the level of uncertainty associated with future production estimates and development decisions. Uncertainty can kill projects, so reducing that uncertainty can allow projects to proceed and add value to the company. These two issues, defining reservoir management impact and quantifying economic impact, will be discussed in the sections that follow. It is assumed in this paper that 4D projects have been, are, or will be technical successes; this is done to allow a focus on the economic issues of quantifying value. The issues of technical risk have been well discussed elsewhere.4,6,7 Defining Reservoir Management Impact Information must be used to impact reservoir management, but there are many different potential uses, some more obvious than others. While it is not possible to generate an exhaustive list, this section lists and discusses some of the most beneficial and common impacts. In general, field economics can be improved by accelerating production, increasing or extending plateau production rate, reducing the rate of decline after plateau, or extending field life to delay abandonment. A new well, properly placed, can achieve all of these benefits, although the plateau production rate is often limited by external constraints and is thus not changeable. If poorly placed, the well may encounter high water saturation immediately, or it may water out rapidly, for example. Given the resulting range of possible economic outcomes, information such as 4D that helps to guide the placement of the well can have a significant, and quantifiable, value. Avoiding Poor Well Placement. 4D results can prevent poor well placement by assessing the state of the reservoir at a planned well location. If oil has been produced from the location, or soon will be, it would not be an economic location for the well. The value of this 4D information is saving the cost of an unnecessary well. In areas in which the cost of drilling wells is greater than the cost of a 4D project, this alone can be a significant impact. Optimizing Placement of New Wells. When 4D results are used to plan a new well location, it is possible to optimize the placement of that well. When undrained compartments are identified by 4D, one can locate a well within the compartment to access the additional reserves. Alternatively, wells can be located away from advancing fluid fronts and/or protected from fronts by natural flow barriers within the field. By doing so, it may be possible to extend plateau production or decrease the decline rate after plateau. Locating Undrained Reservoir Compartments. When 4D indicates no reservoir change in areas expected to be in production, it is likely that those areas of the reservoir are isolated reservoir compartments. This represents oil that was booked as recoverable but will not be recovered with the current well pattern, resulting in a shortening of plateau production and lower ultimate recovery. By locating the compartment, 4D serves to quantify the lost reserves and allow placement of a well to access it. Identifying Drained Areas/Fluid Fronts. Locating drained areas and fluid fronts with 4D gives a direct indication of the flow units in the reservoir. With this information, it is possible to anticipate early breakthrough, potentially in time to adjust field production rates to prevent breakthrough from occurring. This information is also important for locating new wells away from fluid fronts to extend the plateau and accelerate production.
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Al Khatib, Habib, Yessine Boubaker, and Elodie Morgan. "Breaking the seismic 4D ‘image’ paradigm of seismic monitoring." First Break 39, no. 9 (September 1, 2021): 85–91. http://dx.doi.org/10.3997/1365-2397.fb2021072.
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Meza, Ramses, Guy Duncan, Konstantinos Kostas, Stanislav Kuzmin, Mauricio Florez, Tom Perrett, and James Stewart. "Time-lapse seismic monitoring methodologies applied to the Pyrenees Field, offshore Western Australia." APPEA Journal 55, no. 2 (2015): 412. http://dx.doi.org/10.1071/aj14047.
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Time-lapse dedicated 3D seismic surveys were acquired across the Pyrenees oil and gas field, Exmouth Sub-basin to map production-induced changes in the reservoir. Rock-physics 4D modelling showed that changes in pore pressure and fluid saturation would produce a time-lapse seismic response of sufficient magnitude, in both amplitude and velocity, to overcome time-lapse noise. The dominant observed effect is associated with gas coming out of solution. The reservoir simulation model forecasted that reservoir depletion would cause gas breakout that would impact the elastic properties of the reservoir. The effect of gas breakout can be clearly observed on the 4D seismic data as a change in both amplitude and velocity. The analysis of the seismic datasets was proven to be enhanced significantly by using inversion methodologies. These included a band-limited extended-elastic impedance (EEI) approach, as well as simultaneous 4D elastic inversion. These datasets, combined with rock physics modelling, enabled quantitative interpretation of the change in 4D seismic response which was a key tool for assisting with the infill well placement and field development strategy.
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Long, A. S., M. Widmaier, and M. A. Schonewille. "4D PLANNING AND EXECUTION STRATEGIES FOR AUSTRALIAN RESERVOIR MONITORING PROJECTS." APPEA Journal 46, no. 1 (2006): 67. http://dx.doi.org/10.1071/aj05004.
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Time-lapse (4D) reservoir monitoring is in its infancy in Australia, but is on the verge of becoming a mainstream pursuit. We describe the 4D seismic acquisition and processing strategies that have been developed and proven elsewhere in the world, and customise those strategies for Australasian applications.We demonstrate how a multidisciplinary pursuit of real-time acquisition and processing Quality Control (QC) is an integral component of any 4D project. The acquisition and processing geophysicists must be able to understand all the factors contributing to the 4D seismic signal as they happen. Such an understanding can only arise through rigorous project QC and management using interactive visualisation technology. In turn, the production geologists and reservoir engineers will then receive 4D seismic products that can be robustly and confidently used for the construction of accurate reservoir models and the pursuit of reliable reservoir simulations and forecasts.
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Effiom, Oghogho, Robert Maskall, Edwin Quadt, Kazeem A. Lawal, Raphael Afolabi, Jake Emakpor, and Reginald Mbah. "4D seismic interpretation in a Nigerian deepwater field." Interpretation 3, no. 2 (May 1, 2015): SP11—SP19. http://dx.doi.org/10.1190/int-2014-0198.1.
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To improve the management of a Nigerian deep water field, two vintages of 4D data have been acquired since field start up in 2005. The first Nigerian 4D seismic (monitor-I) in water depths greater than 1000 m was taken in this field in 2008, and the second monitor (monitor-II) was acquired in 2012. Compared to monitor-I, better geometric repeatability was achieved in monitor-II as the lessons learned from monitor-I were incorporated to achieve better results. The final normalized root mean square of monitor-II fast-track volume was 12% compared to 25% for monitor-I. The improved quality is attributed to improvements in the acquisition methodology and prediction of the effects of currents. Seismic interpretation of the field revealed two distinct turbidite depositional settings: (1) An unconfined amalgamated lobe system with low relief, high net-to-gross reservoir sands that exhibit fairly homogeneous water flooding patterns on 4D and (2) an erosional canyon setting, filled with meander belts having a more complex 3D connectivity within and between the channels resulting in a challenging 4D interpretation. The time lapse data were instrumental for better understanding the reservoir architecture, enabling improved wells and reservoir management practices, the identification of infill opportunities, and more mature subsurface models. We evaluated the seismic acquisition and the 4D interpretation of the deepwater 4D seismic data, highlighting the merits of a multidisciplinary collaborative understanding to time-lapse seismic. At present, the value of information of the 4D monitor-II is conservatively estimated at 101 million United States dollars, equivalent to the cost of a well in this deepwater operating environment.
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Baytok, Sait, Şeref Arzu Aktepe, and Muhlis Ünaldi. "Amplitude variation with offset analysis of time-lapse land seismic data in a gas field, Thrace Basin, Turkey." Interpretation 4, no. 4 (November 1, 2016): T543—T556. http://dx.doi.org/10.1190/int-2015-0186.1.
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The Thrace Basin that is located in northwestern Turkey contains sandstone and carbonate reservoirs of Eocene and Oligocene age. Production and exploration activities are still underway. Mapping undrained sweet spots from seismic data is currently a challenge, so time lapse (4D) seismic is used to reduce the risk for new production and development drilling. We have evaluated the normalization and amplitude variation with offset (AVO) analysis of 3D-4D land seismic data in a gas producing field from which baseline and monitor surveys were acquired in 2002 and 2011, respectively. Through AVO analysis, intercept (A) and gradient (B) analysis was conducted, and fluid factor (FF) attribute maps were generated for the assessment of the remaining potential areas. Synthetic gathers were created for simulation of the AVO response, drained and undrained stages and compared with the corresponding 4D seismic data. The drainage of gas from the reservoir interval is evident from the difference maps between 2002 and 2011 seismic data. Both data sets were processed using an amplitude friendly processing sequence. This parallel processing was followed a mild data conditioning and crossequalization for reliable 4D interpretation. The 4D seismic data, especially land data, has low repeatability and requires conditioning to reduce the 4D noise. The 4D noise can be described as nonrepeatable noise, and any difference outside the reservoir zone is not related to production. A so-called crossequalization was applied to the base and the monitor data to bring out similarities so that they cancel out when differences of seismic data and its attributes indicated only the production results over the reservoir zones. As the available 4D data crossequalization software was implemented for stack data only, we created angle band stacks and crossequalized each angle band stack from the base and the monitor data cubes. Five angle band stacks from the base and the monitor prestack data cubes 0°–55° (0°–15°, 15°–25°, 25°–35°, 35°–45°, and 45°–55°) were crossequalized individually. The crossequalized angle band stacks were used in AVO analysis and AVO inversion to generate pore fill identifiers such as FF to map possible undrained zones after 10 years of production.
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Asaka, Michinori, Mu Luo, Takashi Yamatani, Ayato Kato, Keita Yoshimatsu, and Levi Knapp. "4D seismic feasibility study: The importance of anisotropy and hysteresis." Leading Edge 37, no. 9 (September 2018): 688–98. http://dx.doi.org/10.1190/tle37090688.1.
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Core velocity measurements are an essential part of any 4D seismic feasibility study. During recently conducted core velocity measurements, we found some interesting results regarding velocity anisotropy and hysteresis. These findings include: (1) the stress sensitivity of velocity varies depending on the propagation direction, (2) velocities measured during loading have a significantly larger stress sensitivity than those measured during unloading, and (3) horizontal effective stress has a noticeable impact on velocity anisotropy. We conducted rock physics analysis and 1D seismic forward modeling, incorporating velocity anisotropy, and found that the estimated 4D seismic signal is largely affected by velocity anisotropy and hysteresis. These findings suggest the importance of considering the velocity measurement direction and the nature of the stress change to obtain a realistic 4D seismic signal. Neglecting these considerations may lead to a significantly underestimated or overestimated modeled seismic response.
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Brice, T., L. Larsen, S. Morice, and M. Svendsun. "4D-READY SEISMIC WITH Q-MARINE." APPEA Journal 41, no. 1 (2001): 671. http://dx.doi.org/10.1071/aj00037.
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A new concept for acquiring calibrated towed streamer seismic data is introduced through a new acquisition and processing system called ‘Q-Marine’. The specification of the new system has been defined by rigorous analysis of the factors that limit the sensitivity of seismic data in 4D studies and imaging. New sensor and streamer technology, new source technology and advances in positioning techniques and data processing have addressed these limitations.Sensitivity analysis revealed that the most significant perturbations to the seismic signal are swell noise and sensor sensitivity variations. Conventional analog groups of hydrophones are designed to suppress swell noise however a new technique for data-adaptive coherent noise attenuation delivers even greater noise suppression for densely spatially sampled single-sensor data.Although modern source controllers provide accurate airgun firing control, the signature of an airgun array may vary from shot to shot. This can be due to factors such as changes in the array geometry, air pressure variations, depth variations and wave action. A method for estimating the far-field signature of a source array is the Notional Source Method (proprietary to Schlumberger) which has been steadily refined since its first disclosure. A recent development compensates for variation in source array geometry by monitoring the position and azimuth of each subarray using GPS receivers mounted on the floats.New calibrated positioning and streamer control systems are part of the new acquisition system. Active vertical and lateral streamer control is achieved using steerable birds and positioning uncertainty is reduced through an in-built fully braced acoustic ranging system.Calibrated marine seismic data are achieved through quantifying the source output, the sensor responses and positioning uncertainty. The consequential improvements in seismic fidelity result in better imaging and more reliable 4D analysis.
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Duncan, Guy, James Cai, Kon Kostas, Tom Perrett, Mauricio Florez, James Stewart, and Stas Kuzmin. "4D Seismic over the Pyrenees Fields." ASEG Extended Abstracts 2015, no. 1 (December 2015): 1–4. http://dx.doi.org/10.1071/aseg2015ab150.
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Lumley, David. "4D seismic monitoring of CO2 sequestration." Leading Edge 29, no. 2 (February 2010): 150–55. http://dx.doi.org/10.1190/1.3304817.
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Lumley, David. "4D seismic monitoring of CO2 sequestration." ASEG Extended Abstracts 2010, no. 1 (December 2010): 1–4. http://dx.doi.org/10.1081/22020586.2010.12041906.
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Jack, Ian. "4D seismic — Past, present, and future." Leading Edge 36, no. 5 (May 2017): 386–92. http://dx.doi.org/10.1190/tle36050386.1.
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Staples, Rob, Paul Hague, Toon Weisenborn, Peter Ashton, and Barbara Michalek. "4D seismic for oil-rim monitoring." Geophysical Prospecting 53, no. 2 (March 2005): 243–51. http://dx.doi.org/10.1111/j.1365-2478.2004.00468.x.
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MacBeth, Colin, Mariano Floricich, and Juan Soldo. "Going quantitative with 4D seismic analysis." Geophysical Prospecting 54, no. 3 (May 2006): 303–17. http://dx.doi.org/10.1111/j.1365-2478.2006.00536.x.
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Waage, Malin, Stefan Bünz, Martin Landrø, Andreia Plaza-Faverola, and Kate A. Waghorn. "Repeatability of high-resolution 3D seismic data." GEOPHYSICS 84, no. 1 (January 1, 2019): B75—B94. http://dx.doi.org/10.1190/geo2018-0099.1.
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High-resolution 4D (HR4D) seismic data have the potential for improving the current state-of-the-art in detecting shallow ([Formula: see text] below seafloor) subsurface changes on a very fine scale (approximately 3–6 m). Time-lapse seismic investigations commonly use conventional broadband seismic data, considered low to moderate resolution in our context. We have developed the first comprehensive time -lapse analysis of high-resolution seismic data by assessing the repeatability of P-cable 3D seismic data (approximately 30–350 Hz) with short offsets and a high density of receivers. P-cable 3D seismic data sets have for decades been used to investigate shallow fluid flow and gas-hydrate systems. We analyze P-cable high-resolution 4D (HR4D) seismic data from three different geologic settings in the Arctic Circle. The first two are test sites with no evidence of shallow subsurface fluid flow, and the third is an active seepage site. Using these sites, we evaluate the reliability of the P-cable 3D seismic technology as a time-lapse tool and establish a 4D acquisition and processing workflow. Weather, waves, tide, and acquisition-parameters such as residual shot noise are factors affecting seismic repeatability. We achieve reasonable quantitative repeatability measures in stratified marine sediments at two test locations. However, repeatability is limited in areas that have poor penetration of seismic energy through the seafloor, such as glacial moraines or rough surface topography. The 4D anomalies in the active seepage site are spatially restricted to areas of focused fluid flow and might likely indicate changes in fluid flow. This approach can thus be applied to detect migration of fluids in active leakage structures, such as gas chimneys.
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Kuzmin, Stanislav, Mauricio Florez, Guy Duncan, and Konstantinos Kostas. "Rock physics modelling and analysis of time-lapse seismic response in the Pyrenees Field, offshore Western Australia." APPEA Journal 55, no. 2 (2015): 470. http://dx.doi.org/10.1071/aj14105.
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Rock physics modelling of the time-lapse seismic response of the Pyrenees Field was carried out to evaluate the feasibility of monitoring reservoir drainage and performance. Initially, the purpose of 4D seismic was to monitor the upward displacement of the oil-water contact. It was recognised that the likelihood of gas breakout imposed a significant risk to the feasibility of monitoring the oil-water contact. Models for different scenarios were used to assess this uncertainty and demonstrated that, in either case, an observable change in seismic properties would occur, providing technical support for 4D seismic acquisition. The monitor seismic survey acquired in 2013, showed detectable changes in both interval velocity and reflectivity that was associated with gas coming out of solution in the reservoir, where depletion occurred below the bubble point. This agrees with pre-acquisition predictions based on rock physics modelling. Additional rock physics analysis was carried out to calibrate the observed 4D response to changes in both fluid saturation and effective stress.
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Thore, Pierre, and Christian Hubans. "4D seismic-to-well tying, a key step towards 4D inversion." GEOPHYSICS 77, no. 6 (November 1, 2012): R227—R238. http://dx.doi.org/10.1190/geo2011-0267.1.
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Calibrating the 4D signal at the well with information obtained from production data is essential for it to be used quantitatively. We have developed a model-based inversion method to estimate the changes of elastic parameters in the reservoir due to production at the well. Our scheme is based on the observation that flow behavior is constrained by the dynamic properties of the layer (i.e., permeability), and, therefore, a layered model should be used to parameterize the inversion. The inversion scheme considers traveltime (inside and below the reservoir, but not in the overburden) and impedance effects implied by the change of elastic parameters (inside the reservoir). Therefore, even at zero offset, we can separate changes in density from changes in P-velocity. When using multiple offset data, we can use an exact formulation for the reflectivity if the base logs (density, P-velocity, and S-velocity) are available, otherwise, an approximation to the exact form can be used. Theoretical and practical analyses have shown that P-velocity is the best resolved parameter followed by density and, finally, S-velocity. Compared to classical data-driven inversion, our procedure introduces fewer artifacts and is less sensitive to tuning because the layered model parameterization introduces the missing low and high frequencies (although the seismic bandwidth plays an essential role in the resolution). This 4D inversion at the well is part of a larger scheme that uses the results obtained by this scheme to extend the inversion to the whole data set.
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Waggoner, J. R. "Lessons Learned From 4D Projects." SPE Reservoir Evaluation & Engineering 3, no. 04 (August 1, 2000): 310–18. http://dx.doi.org/10.2118/65369-pa.
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Summary Time-lapse three-dimensional, or four-dimensional (4D), seismic has been under consideration by the industry for reservoir monitoring for more than a decade. It offers the possibility of identifying the interwell distribution of bypassed and untapped oil, of monitoring displacement heterogeneity, and of detecting uneven pressure depletion away from wells. If obtained, these detailed observations could be used to increase ultimate recovery, reduce production costs, and prevent surprises such as unexpectedly early breakthrough. But these benefits are not easily obtained, and are certainly not guaranteed. There are a number of factors that impact whether a 4D project will be successful, and a careful study of these is required to give a realistic expectation of what 4D can do for a specific reservoir. Numerous 4D seismic projects have been active over oil fields world wide, and successes, relative to each project's objectives, have been realized by field operators using a wide variety of data acquisition techniques (land, streamer, and seabed methods), and over a variety of field types, including both clastics and carbonates. This paper draws from this experience to present a generalized 4D project workflow, and reviews results from some of these recent projects as illustrations. In general, sufficient software tools, rock physics data, and experience now exist to conclude that 4D is a low-risk/high-benefit reservoir management tool. The key to a successful project, however, is determining what 4D can do in a specific field, which requires a careful feasibility study, clear reservoir management objectives, and high-quality and experienced seismic processing and interpretation. Introduction Time-lapse three-dimensional (3D), or four-dimensional (4D), seismic has received a great deal of industry attention and activity over the past few years, as evidenced by the number of conferences organized specifically for 4D seismic and by the number of papers presented at more general conferences. In addition, both the Society of Exploration Geophysicists (SEG) and Society of Petroleum Engineers (SPE) designated Distinguished Lecturers in 1998 that presented excellent material regarding 4D techniques1 and the integration of 4D data with other types of data to improve reservoir description.2 These presentations have been well attended all over the world as the industry seeks to learn more about 4D seismic. What's All the Excitement About? The majority of people are probably interested in the ability of 4D to monitor fluid movement within the reservoir, and subsequently to identify bypassed reserves that can be produced through targeted offset drilling. Another commonly stated benefit of 4D is improved characterization of the reservoir to allow more reliable predictions from reservoir simulation studies, especially as it relates to the effectiveness of water or gas injection processes. These are but two of the extremely valuable reservoir management benefits of 4D seismic; others can be found in the numerous papers on the subject. Is the Excitement Justified? As with most things, the answer is both yes and no. As concluded by several authors,1,3-13 4D has potential, and several case histories to date have shown 4D to work to some degree. It is important to recognize that 4D is a simple idea based on physically limited measurements, difficult processing, and a complex earth. In some sense, it is amazing that it ever works, but experience shows that it can work, and it is that experience that forms the basis for the cautious optimism presented in this paper. Planning for Success Western Geophysical and its predecessors have been doing 4D seismic research, development, planning, and commercial projects, since the early 1980's. From that experience has grown a sound understanding of what it takes to do a successful 4D project. This paper is a collection of brief case histories within the framework of the following systematic and generalized 4D work flow: establish a clear reservoir objective; perform a careful feasibility study on the field of interest; do a rapid analysis of existing overlapping datasets; characterize the static reservoir properties; acquire and (re)process new 3D seismic data; analyze time-lapse differences; and characterize the dynamic reservoir properties using 4D results. Most of the cases have been published or presented at recent conferences, to which the reader is referred for more detailed description and analysis. Establish a Clear Reservoir Objective. Two of the general reservoir objectives were mentioned previously, and repeating a longer list would only serve to heighten the expectation that 4D will solve all problems. In fact, there are a large number of problems that surface seismic cannot address because of the physical limitations of the measurement. For example, 4D will never be able to see the movement of a heavy oil/water interface in a 10 ft thick carbonate at 15,000 ft depth under a large gas cloud. Even if it could, that information would only be of use to you if that was the condition in your reservoir. The goal here is to define what needs to be learned about the reservoir so that the 4D project can be properly planned and the results can be measured against whether the needed information was, in fact, provided by the seismic data. To date, most 4D projects have been performed primarily as a geophysical exercise, rather than with a primary reservoir objective, in order to "test" the 4D technique. For these studies, the stated objective is to take two existing 3D datasets, which happen to have some overlap, and see what the difference between them shows. An example of such a rapid analysis is shown in a later section. The most common result is a suggestion of a difference and a recommendation that the datasets be reprocessed, because the acquisition and processing were of different vintages and for different purposes. However, because the objective is not driven by a reservoir need, there are few examples of even a good geophysical result being used to influence a development or production decision. The important point in setting the reservoir objective is that it be set by the reservoir engineer or asset team to gain needed information. Not only is every reservoir different, but the objective for a particular reservoir will change during its development and production lifetime. Once set, the objectives need to be evaluated as part of the feasibility study that follows to avoid unrealistic expectations.
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Wong, Lee Jean, Hamed Amini, and Colin MacBeth. "Noisy 4D seismic data interpretation: Case study of a Brazilian carbonate reservoir." Leading Edge 39, no. 7 (July 2020): 488–96. http://dx.doi.org/10.1190/tle39070488.1.
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A legacy seismic data set from 2001 and 2011 was used for time-lapse interpretation over a Brazilian carbonate reservoir in Field-X of Campos Basin. The acquired 4D seismic data set was noisy and initially deemed to be uninterpretable. Pressure data were limited, and the initial simulation model was poorly calibrated. All of these challenges warranted the need to establish an interdisciplinary interpretation workflow. In this paper, we introduce a tiered integrated approach to optimize data value from multiple sources. The results of interwell connectivity from production data analysis were used as a basis for assignment of 4D signal confidence flags, which were later combined with simulation-to-seismic modeling of history-matched realizations, enabling interpretation efforts of the noisy 4D seismic data set. This integrated approach led to identification of the injected water front and a potential sweet spot for an infill well.
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Hussein, Marwa, Robert R. Stewart, Deborah Sacrey, David H. Johnston, and Jonny Wu. "Unsupervised machine learning for time-lapse seismic studies and reservoir monitoring." Interpretation 9, no. 3 (July 1, 2021): T791—T807. http://dx.doi.org/10.1190/int-2020-0176.1.
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Time-lapse (4D) seismic analysis plays a vital role in reservoir management and reservoir simulation model updates. However, 4D seismic data are subject to interference and tuning effects. Being able to resolve and monitor thin reservoirs of different quality can aid in optimizing infill drilling or in locating bypassed hydrocarbons. Using 4D seismic data from the Maui field in the offshore Taranaki Basin of New Zealand, we generate typical seismic attributes sensitive to reservoir thickness and rock properties. We find that spectral instantaneous attributes extracted from time-lapse seismic data illuminate more detailed reservoir features compared with those same attributes computed on broadband seismic data. We have developed an unsupervised machine-learning workflow that enables us to combine eight spectral instantaneous seismic attributes into single classification volumes for the baseline and monitor surveys using self-organizing maps (SOMs). Changes in the SOM natural clusters between the baseline and monitor surveys suggest production-related changes that are caused primarily by water replacing gas as the reservoir is being swept under a strong water drive. The classification volumes also facilitate monitoring water saturation changes within thin reservoirs (ranging from very good to poor quality) as well as illuminating thin baffles. Thus, these SOM classification volumes indicate internal reservoir heterogeneity that can be incorporated into reservoir simulation models. Using meaningful SOM clusters, geobodies are generated for the baseline and monitor SOM classifications. The recoverable gas reserves for those geobodies are then computed and compared with production data. The SOM classifications of the Maui 4D seismic data seem to be sensitive to water saturation change and subtle pressure depletions due to gas production under a strong water drive.
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Li, Lin, and Jinfeng Ma. "The influence of pore system change during CO2 storage on 4D seismic interpretation." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 81. http://dx.doi.org/10.2516/ogst/2019047.
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A 4D seismic forward model constitutes the foundation of 4D seismic inversion. Here, in combination with the Gassmann equation, the Digby model is improved to calculate the S-wave velocity, and the resulting equation is verified using rock testing results. Then, considering the influences of changes in the pore pressure, CO2 saturation and porosity on the P- and S- wave velocities, rock testing results from a CO2 injection area in the Weyburn field are used to calculate the P- and S-wave velocities of the reservoir. These P- and S-wave velocities are found to overlap under different pressure conditions with or without considering porosity variations. Therefore, two-layer models and well models are developed to simulate synthetic seismograms; the models considering porosity variations may provide greater seismic responses and different Amplitude Versus Offset (AVO) trends in the synthetic seismogram profiles than those without considering porosity variations. Thus, porosity variations must be considered when establishing 4D seismic forward models.
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Saul, Matthew, and David Lumley. "The combined effects of pressure and cementation on 4D seismic data." GEOPHYSICS 80, no. 2 (March 1, 2015): WA135—WA148. http://dx.doi.org/10.1190/geo2014-0226.1.
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Time-lapse seismology has proven to be a useful method for monitoring reservoir fluid flow, identifying unproduced hydrocarbons and injected fluids, and improving overall reservoir management decisions. The large magnitudes of observed time-lapse seismic anomalies associated with strong pore pressure increases are sometimes not explainable by velocity-pressure relationships determined by fitting elastic theory to core data. This can lead to difficulties in interpreting time-lapse seismic data in terms of physically realizable changes in reservoir properties during injection. It is commonly assumed that certain geologic properties remain constant during fluid production/injection, including rock porosity and grain cementation. We have developed a new nonelastic method based on rock physics diagnostics to describe the pressure sensitivity of rock properties that includes changes in the grain contact cement, and we applied the method to a 4D seismic data example from offshore Australia. We found that water injection at high pore pressure may mechanically weaken the poorly consolidated reservoir sands in a nonelastic manner, allowing us to explain observed 4D seismic signals that are larger than can be predicted by elastic theory fits to the core data. A comparison of our new model with the observed 4D seismic response around a large water injector suggested a significant mechanical weakening of the reservoir rock, consistent with a decrease in the effective grain contact cement from 2.5% at the time/pressure of the preinjection baseline survey, to 0.75% at the time/pressure of the monitor survey. This approach may enable more accurate interpretations and future predictions of the 4D signal for subsequent monitor surveys and improve 4D feasibility and interpretation studies in other reservoirs with geomechanically similar rocks.
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Maxwell, S. C., and T. I. Urbancic. "The Potential Role of Passive Seismic Monitoring for Real-Time 4D Reservoir Characterization." SPE Reservoir Evaluation & Engineering 8, no. 01 (February 1, 2005): 70–76. http://dx.doi.org/10.2118/89071-pa.
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Summary This paper details the application of passive seismic monitoring to image reservoir fracturing and deformation from the stage of an initial wellcompletion to final field production. Instrumented oil fields with seismic arrays either permanently installed or temporarily deployed on wireline offer the possibility of imaging production activities in a real-time sense that complements other seismic-reflection and engineering measurements. During the well-completion stage of development, real-time microseismic imaging offers the possibility of monitoring well stimulation. Fracture images may be used to optimize the fracture design and the net present value (NPV) of well production, as well as understand fracture complexity and the associated well-drainage pattern to target future well placement. During production stages, time-lapse microseismic imaging may be used for image deformation associated with fracturing or fracture reactivation from pressure or stress changes, strains in the overburden in fields with casing-deformation problems, and image fronts associated with secondary recovery. In this paper, several case studies are used to illustrate various potential applications, along with discussion of the potential limitations. The reservoir conditions necessary for the successful application of the technology are presented along with a potential method to quantify the technical feasibility at a particular site. Introduction With the current industry trend toward instrumented oil fields and smart-well completions, the permanent deployment of geophones or other acoustic sensors to complement standard engineering gauges is being promoted as a way to map reservoir dynamics. The biggest push is from active time-lapse seismic, although the deployment of permanent seismic instrumentation is also potentially an ideal route to monitor passive seismicity. Passive monitoring of acoustic emissions, or small-magnitude microearthquakes (microseismicity)associated with stress changes in and around the reservoir, can also be used to image the reservoir dynamics. Passive monitoring has the benefit of more fully using the seismic sensors to monitor during periods between conventional seismic surveys, directly imaging fracturing and deformation, and offers complementary information to both active time-lapse images and engineering measurements. Microseismic events, related to either induced movements on pre-existing structures or the creation of new fractures, capture deformations as the rock mass reacts to stresses and strains associated with pressure changes in the reservoir. The microseismicity can be used to localize the fracturing or to deduce geomechanical details of the deformation. Since the Rangely experiment in the late 1960s,1 a number of passive seismic experiments have been pursued in the petroleum industry with varying degrees of success.2–5 Recently, an umber of independent operators have successfully implemented passive seismic studies to address specific issues. The majority of these studies are under the umbrella of hydraulic fracturing,2,3 where the microseismicity is used to map the fracture growth directly during well stimulations. However, a number of other studies have been used to image deformations associated with primary production,4 secondary recovery,4 or waste-injection operations.5 In the vast majority of these cases, an array of seismic sensors is deployed by wireline to monitor for a specific period. This requires finding a well "close to the action" to facilitate detection of these small passive signals without impacting production. Permanent sensor deployment in an instrumented oil field circumvents the chronic problem of well availability. In numerous fields, microseismicity is continually occurring, and if the instrumentation were in place to record the data properly, additional information on the reservoir performance could be gained. As an aside, it is worth considering how much of the "noise" recorded in conventional seismics may be actually valuable microseismic data. The key will be to design the seismic arrays properly to cover both conventional active seismics (e.g., reflection and tomography) and specific issues associated with passive recording. This paper will outline a viewpoint of the potential applications and technical issues associated with passive seismic monitoring. Because passive seismics is probably best viewed as being in its infancy in the petroleum industry, it is worth standing back and considering applications in other industries in which the technology is more mature. In mining, real-time micro seismic data are used by supervisors to decide if it is safe to send miners underground.6 Microseismic data are also crucial in a number of other rock-engineering applications, such as excavation stability in nuclear-wasterepositories,7 geotechnical stability,8 and performance of geothermal reservoirs.9 Permanent instrumentation in oil fields also should allow the maturity of the technology to help solve certain geomechanical problems in the petroleum industry. This article generally will focus on borehole deployments because passive monitoring will most likely involve borehole arrays to keep the instrumentation close to the action and maximize sensitivity. In some special cases, where induced seismic activity can be detected at surface, permanent surface arrays could be used in a context similar to the picture painted in this paper. However, for the most part, the following discussion will focus on borehole arrays.
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Gavin, Lisa J., and David Lumley. "The effects of azimuthal anisotropy on 3D and 4D seismic amplitude variation with offset responses." GEOPHYSICS 84, no. 6 (November 1, 2019): C251—C267. http://dx.doi.org/10.1190/geo2018-0450.1.
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Seismic reflection amplitude variation with source-receiver offset (AVO) is an important tool in hydrocarbon exploration and reservoir monitoring, due to its sensitivity to elastic rock properties that are affected by changes in pore-fluid saturation and pressure. In most cases, 4D seismic feasibility studies and interpretation analyses assume that the earth is isotropic. This assumption can be problematic because it is becoming increasingly apparent that anisotropic rocks are quite common. Furthermore, the presence of even small amounts of anisotropy can have significant effects on AVO, and in the presence of azimuthal anisotropy the AVO will vary with azimuth. We determine that if 4D seismic surveys are acquired with different survey azimuths in the presence of azimuthal anisotropy, it is likely that 4D AVO interpretations will be significantly affected, leading to incorrect or nonphysical interpretations. This possibility is especially apparent in the context of the North West Shelf, Australia, where significant stress-induced azimuthal anisotropy is prevalent in sandstone formations that form the reservoir rocks. We model 4D AVO responses with and without azimuthal anisotropy effects for a variety of pore-fluid saturation and pressure change scenarios using average reservoir properties from the Stybarrow field, Australia. We found that azimuthal anisotropy does not affect the small reflection angles of the 4D AVO response, but it has a significant effect on larger reflection angles when comparing 4D surveys acquired at different acquisition azimuths. This azimuthal behavior leads to what we call an “apparent 4D effect” when reservoir properties do not change and a “contaminated 4D effect” when reservoir properties do change. We found real data examples in which we determine that the 4D AVO response must incorporate azimuthal anisotropy to be explained correctly. Our results further emphasize the importance of repeating survey acquisition azimuths whenever possible and/or accurately accounting for azimuthal anisotropy effects.
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dos Santos, Juliana Maia Carvalho, Alessandra Davolio, Denis Jose Schiozer, and Colin MacBeth. "Semiquantitative 4D seismic interpretation integrated with reservoir simulation: Application to the Norne field." Interpretation 6, no. 3 (August 1, 2018): T601—T611. http://dx.doi.org/10.1190/int-2017-0122.1.
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Time-lapse (or 4D) seismic attributes are extensively used as inputs to history matching workflows. However, this integration can potentially bring problems if performed incorrectly. Some of the uncertainties regarding seismic acquisition, processing, and interpretation can be inadvertently incorporated into the reservoir simulation model yielding an erroneous production forecast. Very often, the information provided by 4D seismic can be noisy or ambiguous. For this reason, it is necessary to estimate the level of confidence on the data prior to its transfer to the simulation model process. The methodology presented in this paper aims to diagnose which information from 4D seismic that we are confident enough to include in the model. Two passes of seismic interpretation are proposed: the first, intended to understand the character and quality of the seismic data and, the second, to compare the simulation-to-seismic synthetic response with the observed seismic signal. The methodology is applied to the Norne field benchmark case in which we find several examples of inconsistencies between the synthetic and real responses and we evaluate whether these are caused by a simulation model inaccuracy or by uncertainties in the actual observed seismic. After a careful qualitative and semiquantitative analysis, the confidence level of the interpretation is determined. Simulation model updates can be suggested according to the outcome from this analysis. The main contribution of this work is to introduce a diagnostic step that classifies the seismic interpretation reliability considering the uncertainties inherent in these data. The results indicate that a medium to high interpretation confidence can be achieved even for poorly repeated data.
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Fanchi, John R. "Embedding a Petroelastic Model in a Multipurpose Flow Simulator To Enhance the Value of 4D Seismic." SPE Reservoir Evaluation & Engineering 13, no. 01 (February 4, 2010): 37–43. http://dx.doi.org/10.2118/118839-pa.
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Summary Time-lapse (4D) seismic can be effectively integrated into the reservoir-management process by embedding the calculation of seismic attributes in a flow simulator. This paper describes a petroelastic model (PEM) embedded in a multipurpose flow simulator. The flow simulator may be used to model gas, black-oil, compositional, and thermal systems. The PEM can calculate reservoir geophysical attributes such as compressional-wave (P-wave) and shear-wave (S-wave) velocities and impedances, dynamic and static Young's moduli, and dynamic and static Poisson's ratios. Examples illustrate how to use the PEM to facilitate the integration of 4D seismic and reservoir flow modeling.
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Dubos-Sallée, Noalwenn, André Fourno, Jeanneth Zarate-Rada, Véronique Gervais, Patrick N. J. Rasolofosaon, and Olivier Lerat. "A complete workflow applied on an oil reservoir analogue to evaluate the ability of 4D seismics to anticipate the success of a chemical enhanced oil recovery process." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 75 (2020): 18. http://dx.doi.org/10.2516/ogst/2020011.
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In an Enhanced Oil Recovery (EOR) process, one of the main difficulties is to quickly evaluate if the injected chemical products actually improve oil recovery in the reservoir. The efficiency of the process can be monitored in the vicinity of wells, but it may take time to estimate it globally in the reservoir. The objective of this paper is to investigate the ability of 4D seismics to bridge this gap and to help predict the success or breakdown of a production strategy at reservoir scale. To that purpose, we consider a complete workflow for simulating realistic reservoir exploitation using chemical EOR and 4D seismic modeling. This workflow spans from geological description to seismic monitoring simulation and seismic attributes analysis, through geological and reservoir modeling. It is applied here on a realistic case study derived from an outcrop analog of turbiditic reservoirs, for which the efficiency of chemical EOR by polymer and surfactant injection is demonstrated. For this specific field monitoring application, the impact of both waterflooding and proposed EOR injection is visible on the computed seismics. However, EOR injection induces a more continuous water front that can be clearly visible on seismics. In this case, the EOR efficiency can thus be related to the continuity of the water front as seen on seismics. Nevertheless, in other cases, chemical EOR injections may have more moderate impacts, or the field properties may be less adapted to seismic monitoring. This points out the importance of the proposed workflow to check the relevance of seismic monitoring and to design the most adapted monitoring strategy. Numerous perspectives are proposed at the end of the paper. In particular, experts of the different disciplines involved in the proposed workflow can benefit from the availability of a complete set of well-controlled data of various types to test and improve their own tools. In contrast, the non-experts can easily and quickly benefit from “hands-on” experiments for understanding the involved phenomena. Furthermore, the proposed workflow can be directly applied to geological reservoirs all over the world.
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Denney, Dennis. "4D, Multicomponent Seismic Tracks a Miscible Process." Journal of Petroleum Technology 51, no. 06 (June 1, 1999): 40–41. http://dx.doi.org/10.2118/0699-0040-jpt.
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Denney, Dennis. "4D Seismic in the Meren Field, Nigeria." Journal of Petroleum Technology 52, no. 07 (July 1, 2000): 29–30. http://dx.doi.org/10.2118/0700-0029-jpt.
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Rosa, Daiane Rossi, Denis José Schiozer, and Alessandra Davolio. "Enhancing vertical resolution with 4D seismic inversion." Journal of Petroleum Science and Engineering 212 (May 2022): 110291. http://dx.doi.org/10.1016/j.petrol.2022.110291.
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Carpenter, Chris. "4D Seismic Pilot Successfully Interprets Carbonate Reservoir." Journal of Petroleum Technology 71, no. 03 (March 1, 2019): 92–93. http://dx.doi.org/10.2118/0319-0092-jpt.
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Nasser, Mosab, Shuki Ronen, and Jan Stammeijer. "Introduction to this special section: 4D seismic." Leading Edge 35, no. 10 (October 2016): 828–30. http://dx.doi.org/10.1190/tle35100828.1.
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Waal, Hans de, and Rodney Calvert. "Overview of global 4D seismic implementation strategy." Petroleum Geoscience 9, no. 1 (January 2003): 1–6. http://dx.doi.org/10.1144/1354-079302-531.
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Lubrano-Lavadera, P., Å. Drottning, I. Lecomte, B. D. E. Dando, D. Kühn, and V. Oye. "Seismic Modelling: 4D Capabilities for CO2 Injection." Energy Procedia 114 (July 2017): 3432–44. http://dx.doi.org/10.1016/j.egypro.2017.03.1474.
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