SPE Reservoir Evaluation & Engineering最新文献

{"title":"Semianalytical Model for Monitoring Fracture Liquid-Loading in Vertical Fractured Gas Wells","authors":"Zhipeng Wang, Z. Ning, Wen-ming Guo","doi":"10.2118/214318-pa","DOIUrl":"https://doi.org/10.2118/214318-pa","url":null,"abstract":"\u0000 Liquid loading seriously affects gas wells production and even causes gas wells abandonment. Many researchers still focus on correcting a critical liquid-loading flow rate to alleviate these problems. However, they still cannot reasonably be explained. Gas flow rate is higher than the critical liquid-loading flow rate, but liquid loading can still occur. Therefore, until an accurate critical fluid-loading flow rate is discovered, we should monitor the fluid-loading phenomenon to prevent it from affecting production gas wells’ performance. In this work, a fracture liquid-loading monitoring (FLLM) model is proposed and solved for the timely monitoring of fracture liquid-loading (FLL) positions and volume. The Newman product and Green function methods are used to develop and solve the FLLM model. The fracture is discretized into 2nxnz grids to describe an FLL volume and position. The numerical simulation method is used to verify the accuracy of the FLLM model. As a result, four innovative flow regimes, including fracture cavity liquid-loading flow, fracture root liquid-loading flow, transitional flow considering fracture cavity liquid-loading flow, and transitional flow considering fracture root liquid-loading flow, are identified on the pressure response curves. The pressure response of the same gas well at different times is well matched by the model in this paper, and the obtained parameters are more reasonable. The FLLM model can correct for magnified permeability, shortened half-length, and magnified wellbore storage coefficient. In conclusion, the FLLM model is established to monitor FLL, and alert engineers to remove liquid loading on time to prevent water from suddenly rushing into a wellbore and causing gas wells abandonment.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"33 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81010820","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Pressure-Transient Analysis for Waterflooding with the Influence of Dynamic Induced Fracture in Tight Reservoir: Model and Case Studies","authors":"Zhipeng Wang, Z. Ning, Wen-ming Guo, Qidi Cheng","doi":"10.2118/214321-pa","DOIUrl":"https://doi.org/10.2118/214321-pa","url":null,"abstract":"\u0000 It is well known that waterflooding will create fractures. The created fractures are divided into hydraulic fractures (artificial fractures with proppant) and induced fractures (formed during waterflooding without proppant). There is no proppant in the induced fracture, so it will close as the pressure decreases and extend as the pressure increases. We call it a dynamic induced fracture (DIF). Because of reduced pressure, the DIF will be closed during the shut-in pressure test (well testing). The current conventional well-testing model cannot describe the dynamic behavior of the DIF, resulting in obtaining unreasonable parameters. Thus, this work proposes a DIF model to characterize the DIF behavior during well testing (the injection well will shut in, resulting in a reduction in bottomhole pressure and induced-fracture closure). It is worth noting that a high-permeability zone (HPZ) will be formed by long-time waterflooding and particle transport. The HPZ radius will be greater than or equal to the DIF half-length because the waterflooding pressure can move particles but not necessarily expand the fracture. The point source function method and Duhamel principle are used to obtain the bottomhole pressure response. Numerical simulation methods are used to verify the accuracy of the model. Field cases are matched to demonstrate the practicability of the DIF model. Results show a straight line with a slope greater than the unit, a peak, a straight line with a slope less than one-half, and an upturned straight line on the pressure derivative curve. This peak can move up, down, left, and right to characterize the induced fracture’s dynamic conductivity (DC). The straight line with a slope greater than the unit can illustrate a fracture storage effect. The straight line with a slope less than one-half can describe the closed induced-fracture (CIF) half-length. The upturned straight line can describe the HPZ and reservoir permeability. The obtained parameters will be inaccurate if they are incorrectly identified as other flow regimes. Field cases are matched well to illustrate that identifying the three innovative flow regimes can improve the parameters’ accuracy. In conclusion, the proposed model can characterize the dynamic behavior of induced fracture, better match the field data, and obtain more reasonable reservoir parameters. Finally, two field cases in tight reservoir are discussed to prove its practicality.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"79 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87086785","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Data-Driven Reduced-Order Models for Volve Field Using Reservoir Simulation and Physics-Informed Machine Learning Techniques","authors":"M. Behl, M. Tyagi","doi":"10.2118/214288-pa","DOIUrl":"https://doi.org/10.2118/214288-pa","url":null,"abstract":"\u0000 Reservoir simulation is the industry standard for prediction and characterization of processes in the subsurface. However, large gridblock counts simulation is computationally expensive and time-consuming. This study explores data-driven reduced-order models (ROMs) as an alternative to detailed physics-based simulations. ROMs that use neural networks (NNs) effectively capture nonlinear dependencies and only require available operational data as inputs. NNs are usually labeled black-box tools that are difficult to interpret. On the other hand, physics-informed NNs (PINNs) provide a potential solution to these shortcomings, but they have not yet been applied extensively in petroleum engineering.\u0000 In this study, a black-oil reservoir simulation model from Volve public data release was used to generate training data for an ROM leveraging long short-term memory (LSTM) NNs’ temporal modeling capacity. Network configurations were explored for their optimal configuration. Monthly oil production was forecast at the individual wells and full-field levels, and then validated against real field data for production history to compare its predictive accuracy against the simulation results. The governing equations for a capacitance resistance model (CRM) were then added to the reservoir-scale NN model as a physics-based constraint and to analyze parameter solutions for efficacy in characterization of the flow field.\u0000 Data-driven ROM results indicated that a stateless LSTM, with single time lag as input, generated the most accurate predictions. Using a walk-forward validation strategy, the single well ROM increased prediction accuracy by about 95% average when compared with the reservoir simulation and did so with much less computational resources in short time duration. Physical realism of reservoir-scale predictions was improved by the addition of CRM constraint, demonstrated by the removal of negative flow rates. Parameter solutions to the governing equation showed good agreement with the field-scale streamline plots and demonstrated the ROM ability to detect spatial irregularities. These results clearly demonstrate the ease with which ROMs can be built and used to meet or exceed the predictive capabilities of certain time-history production data using the reservoir simulation.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83896915","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Multiscale Wettability Characterization of Anhydrite-Rich Carbonate Rocks: Insights into Zeta Potential, Flotation, and Contact Angle Measurements","authors":"A. Isah, M. Mahmoud, M. Kamal, M. Arif, M. A. Jawad","doi":"10.2118/214324-pa","DOIUrl":"https://doi.org/10.2118/214324-pa","url":null,"abstract":"\u0000 Anhydrite (CaSO4) is a chemically reactive rock/mineral found predominantly as a constituent of carbonates. The main constituents of anhydrite are calcium and sulfate ions. The presence of anhydrite, its distribution, and the associated anhydrite-fluid interactions are important to precisely evaluate the effectiveness of oil recovery techniques. While anhydrite dissolution is the key interaction mechanism in anhydrite-rich rocks, its presence may also lead to complex rock wetting behavior. The underpinning logic is that pure anhydrite is strongly water-wet, while pure calcite and dolomite are somewhat intermediate to weakly oil-wet, thus the question remains unclear as to what the wettability would be of anhydrite and calcite, and anhydrite and dolomite combinations. Moreover, because anhydrite is negatively charged while dolomite and calcite in formation water (FW) are positively charged, depending on the mixture composition, pH, and brine type, it is not clear what the charge would be of a combination of anhydrite-calcite or anhydrite-dolomite, and, consequently, what the wetting behavior of calcite and dolomite would be due to anhydrite presence. Therefore, this research explores the effect of anhydrite mineral on carbonate wetting characteristics. The effect of mineralogical heterogeneity, specifically the presence of anhydrite minerals in calcite and dolomite wettability, is investigated across a range of scales.\u0000 The results show that anhydrite dissolution occurs in deionized (DI) water, seawater (SW), and FW as evident from the general increase in sulfate ions concentration with increased anhydrite content in the anhydrite-carbonate system. We also found that zeta potential demonstrates an unstable colloidal system, which is indicated by near-zero and low zeta potential values (less than ±10) of the anhydrite-carbonate-brine systems. It also shows a nonmonotonic wetting behavior with brine salinity and pH variations. Accordingly, the zeta potential is not a general and valid candidate to justify the wettability behavior of heterogeneous carbonates. However, based on flotation and contact angle techniques of wettability estimation, anhydrite presence has the tendency to alter the wetting state of anhydrite-carbonate-brine-oil systems to more water-wet. Thus, findings from this research will provide answers to the question of how the mineralogy affects the wetting characteristics of carbonates. What will be the changes in carbonate wetting behavior with mineralogical heterogeneity? Specifically, what would be the wettability of calcite-anhydrite and dolomite-anhydrite combinations? This research therefore provides a systematic investigation of rock/fluid interactions and their implications on wettability and ultimate recovery of oil at different range scales. The findings from this study will significantly enhance our knowledge of fluid-rock interactions, in particular, anhydrite-rich carbonate wetting behavior, thereby reducing the uncert","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"7 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89392384","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates","authors":"Brenda Azuara Diliegros, Roberto Aguilera","doi":"10.2118/208893-pa","DOIUrl":"https://doi.org/10.2118/208893-pa","url":null,"abstract":"Summary This paper develops a method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with permeability less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. The development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with permeability more than 0.1 md. Core data and drill cuttings available for this study are limited but provide important insights for the log interpretation and for identifying the presence of grainstone, packstone, and wackstone rocks in the unconventional tight carbonate under consideration. A crossplot of RFN vs. rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that are supported by well testing data. Information for the analysis of the Mexican carbonate comes from well logs of nine wells and two re-entry wells, four buildup tests, and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95% of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md, thus the need for a methodology that allows estimating from well logs the presence of grainstone, packstone, and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone, and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"30 3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135963610","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Hybrid Embedded Discrete Fracture Model and Dual-Porosity, Dual-Permeability Workflow for Hierarchical Treatment of Fractures in Practical Field Studies","authors":"M. Hui, Bradley T. Mallison, Sunil G. Thomas, Pierre Muron, Matthieu Rousset, E. Earnest, T. Playton, H. Vo, C. Jensen","doi":"10.2118/209293-pa","DOIUrl":"https://doi.org/10.2118/209293-pa","url":null,"abstract":"\u0000 Natural fracture systems comprise numerous small features and relatively few large ones. At field scale, it is impractical to treat all fractures explicitly. We represent the largest fractures using an embedded discrete fracture model (EDFM) and account for smaller ones using a dual-porosity, dual-permeability (DPDK) idealized representation of the fracture network. The hybrid EDFM + DPDK approach uses consistent discretization schemes and efficiently simulates realistic field cases. Further speedup can be obtained using aggregation-based upscaling. Capabilities to visualize and post-process simulation results facilitate understanding for effective management of fractured reservoirs. The proposed approach embeds large discrete fractures as EDFM within a DPDK grid (which contains both matrix and idealized fracture continua for smaller fractures) and captures all connections among the triple media. In contrast with existing EDFM formulations, we account for discrete fracture spacing within each matrix cell via a new matrix-fracture transfer term and use consistent assumptions for classical EDFM and DPDK calculations. In addition, the workflow enables coarse EDFM representations using flow-based cell-aggregation upscaling for computational efficiency. Using a synthetic case, we show that the proposed EDFM + DPDK approach provides a close match of simulation results from a reference model that represents all fractures explicitly, while providing runtime speedup. It is also more accurate than previous standard EDFM and DPDK models. We demonstrate that the matrix-fracture transfer function agrees with flow-based upscaling of high-resolution fracture models. Next, the automated workflow is applied to a waterflooding study for a giant carbonate reservoir, with an ensemble of stochastic fracture realizations. The overall workflow provides the computational efficiency needed for performance forecasts in practical field studies, and the 3D visualization allows for the derivation of insights into recovery mechanisms. Finally, we apply a finite-volume tracer-based flux post-processing scheme on simulation results to analyze production allocation and sweep for understanding expected waterflood performance.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"18 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86039709","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fault Identification for the Purposes of Evaluating the Risk of Induced Seismicity: A Novel Application of the Flowback DFIT","authors":"D. Zeinabady, C. R. Clarkson, S. Razzaghi, S. Haqparast, A. L. Benson, M. Azad","doi":"10.2118/211100-pa","DOIUrl":"https://doi.org/10.2118/211100-pa","url":null,"abstract":"Summary The existence of faults, pre-existing hydraulic fractures, and depleted areas can negatively impact the development of unconventional reservoirs using multifractured horizontal wells (MFHWs). For example, the triggering of fault slippage through hydraulic fracturing can create the environmental hazard known as induced seismicity (earthquakes caused by hydraulic fracturing). A premium has therefore been placed on the development of technologies that can be used to identify the locations of fault systems (particularly if they are subseismic) as well as pre-existing hydraulic fractures and depleted areas. The objective of this study is to develop a diagnostic tool to identify these conditions using DFIT-FBA, a modified diagnostic fracture injection test (DFIT) with flowback analysis (FBA). The time and cost efficiencies of the DFIT-FBA method in reservoir characterization provides an opportunity to conduct multiple field tests at a single point or along the lateral section of a horizontal well. An analytical model that considers critical processes and mechanisms occurring during DFIT-FBA was first developed herein. The results of analytical modeling demonstrate that reservoir heterogeneities (i.e., faults) can be identified either by implementing multiple cycles of the DFIT-FBA method at a single point or by applying multiple DFIT-FBAs at different points along the lateral section of a horizontal well or at different wells. The analytical model is then verified using a fully coupled hydraulic fracture, reservoir, and wellbore simulator, and flowing pressure responses in the presence of a fault are illustrated. The practical application of the proposed method is demonstrated using DFIT-FBA field examples performed in a tight reservoir. Analysis of the field examples leads to the conclusion that a fault likely occurs near the toe of the horizontal lateral. This finding was confirmed by other field information and provides the opportunity to modify the main-stage hydraulic fracturing design to avoid induced seismicity events.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135998053","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"History-Matching and Forecasting Production Rate and Bottomhole Pressure Data Using an Enhanced Physics-Based Data-Driven Simulator","authors":"Ying Li, Faruk Omer Alpak, Vivek Jain, Ranran Lu, Mustafa Onur","doi":"10.2118/210102-pa","DOIUrl":"https://doi.org/10.2118/210102-pa","url":null,"abstract":"Summary In this study, we present a novel application of our newly developed physics-based data-driven interwell numerical simulator (INSIM) referred to as INSIM-BHP to history match highly variable real-life (oscillatory) oil rate and bottomhole pressure (BHP) data acquired daily in multiperforated wells produced from an oil reservoir with bottomwater drive mechanism. INSIM-BHP provides rapid and accurate computation of well rates and BHPs for history matching, forecasting, and production optimization purposes. It delivers precise BHP calculations under the influence of a limited aquifer drive mechanism. Our new version represents the physics of two-phase oil-water flow more authentically by incorporating a harmonic-mean transmissibility computation protocol and including an arithmetic-mean gravity term in the pressure equation. As the specific data set considered in this study contains a sequence of highly variable oil rate and BHP data, the data density requires INSIM-BHP to take smaller than usual timesteps and places a strain on the ensemble-smoother multiple data assimilation (ES-MDA) history-matching algorithm, which utilizes INSIM-BHP as the forward model. Another new feature of our simulator is the use of time-variant well indices and skin factors within the simulator’s well model to account for the effects of well events on reservoir responses such as scaling, sand production, and matrix acidizing. Another novel modification has been made to the wellhead term calculation to better mimic the physics of flow in the wellbore when the production rate is low, or the well(s) is(are) shut in. We compare the accuracy of the history-matched oil rate and BHP data and forecasted results as well as computational efficiency for history matching and future prediction by INSIM-BHP with those from a high-fidelity commercial reservoir simulator. Results show that INSIM-BHP yields accurate forecasting of wells' oil rates and BHPs on a daily level even under the influence of oscillatory rate schedules and changing operational conditions reflected as skin effects at the wells. Besides, it can help diagnose abnormal BHP measurements within simulation runs. Computational costs incurred by INSIM-BHP and a high-fidelity commercial simulator are evaluated for the real data set investigated in this paper. It has been observed that our physics-based, data-driven simulator is about two orders of magnitude faster than a conventional high-fidelity reservoir simulator for a single forward simulation. The specific field application results demonstrate that INSIM-BHP has great potential to be a rapid approximate capability for history matching and forecasting workflow in the investigated limited-volume aquifer-driven development.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136321776","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Thermal Magnetic Properties Variation of Rock During In-Situ Combustion Process","authors":"D. Kuzina, D. Nurgaliev, C. Yuan, V. Morozov, M. Varfolomeev, E. Utemov, L. Chen, J. Pan, W. Pu","doi":"10.2118/214296-pa","DOIUrl":"https://doi.org/10.2118/214296-pa","url":null,"abstract":"\u0000 In-situ combustion (ISC) has been proven as a promising technique for the extraction of heavy oils. It has been used in oil fields since the 1920s; however, it is still not as widely used as steam injection. One of the difficulties limiting its wide application is monitoring and controlling the movement of the combustion front. This work is aimed at studying the change in the properties of rock during the ISC process, which is expected to be used for developing an effective monitoring method of the combustion front movement.\u0000 Rock samples before and after the ISC process were obtained from the Xinjiang Oil field (China) where an ISC industrial pilot has been implemented. In the temperature range of lower than 500℃, the minerals may only alter slightly. Therefore, it is difficult to determine whether the rock was heated or not during the ISC processes using general mineralogical or geochemical methods, for example, X-ray diffraction. This work takes a comprehensive approach to study the variation of rock properties. Magnetic analysis was chosen as the primary method since a very tiny change in the mineral composition during heating leads to profound changes in the magnetic properties. We analyzed magnetic susceptibility (MS), natural remanent magnetization (NRM), hysteresis parameters and thermomagnetic data. In addition, we performed differential thermomagnetic analysis (DTMA) for tracing magnetic minerals based on their Curie temperatures as well as for monitoring transformations in magnetic minerals during heating. Simultaneously, X-ray diffractometer (XRD), optical microscope for thin-sections, and organic content measurements were used as assistive methods to get a comprehensive evaluation on the variation of rock.\u0000 We found that there is a big difference in magnetic minerals between the initial samples (not subjected to the ISC process) and burned samples from different wells and depths in the ISC pilot. Several magnetic clusters with different coercive force and domain structure were found in these samples. Based on the difference in magnetic properties, we found that the burned samples were heated to different temperatures during the ISC process. In addition, for some rock samples, the heating temperature during the ISC process was determined, and an analysis was made of the propagation of the combustion front.\u0000 The thermal magnetic properties variation of rock during the ISC process is obvious, which makes it promising to be used for monitoring the propagation direction of the combustion front. Theoretical calculations of magnetic anomalies that occur due to changes in the magnetic properties of rocks during the ISC process indicate the possibility of the detection of such anomalies from the Earth’s surface through high-precision magnetic surveys. The findings in this work provide a theoretical base and direction for developing combustion front monitoring technologies.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"8 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89015184","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reservoir Modeling, History Matching, and Characterization with a Reservoir Graph Network Model","authors":"Zhenyu Guo, S. Sankaran, Wenyue Sun","doi":"10.2118/209337-pa","DOIUrl":"https://doi.org/10.2118/209337-pa","url":null,"abstract":"\u0000 Efficient reservoir models are more desirable for fast-paced reservoir management. Moreover, due to the complexity of flow underground, it is also essential to capture the fundamental physics for model reliability. Although they are fast, pure data-driven models frequently have issues associated with interpretability, physical consistency, and ability to forecast. On the other hand, we have used full-physics simulation models to mimic and investigate hydrocarbon systems for over several decades. However, considering its infrequent model updates related to high model complexity, it is a big challenge to manage reservoirs using full-physics models in short cycles. The objective here is to propose an approach that blends reservoir physics with data-driven models to fit in the framework of dynamic reservoir management.\u0000 We propose to use a reservoir graph network (RGNet) modeling approach based on a diffusive time-of-flight (DTOF) concept to simulate reservoir behaviors. By assimilating field observation data (such as pressure and rates), an RGNet model can be used for future predictions, scenario studies, and well-control optimizations. By discretizing DTOF of a 3D system with multiple wells, RGNet simplifies the system into a graph network represented by a set of 1D grid blocks that significantly reduces the system complexity and run time. RGNet can also handle multiple flow problems with various types of physics. In this work, we propose to use two methods to develop reliable and parsimonious models scalable to large-scale systems. In addition, we propose a more robust method to assimilate pressure data.\u0000 We applied the proposed approach to a synthetic and a field example. Two different history-matching algorithms, the ensemble smoother with multiple data assimilation (ES-MDA) and an adjoint-based method, are compared. While ES-MDA provides the capability for uncertainty analysis, an adjoint-based method generally requires fewer simulation runs to generate a posterior model. With the proposed methods for generating interwell connections, RGNet model calibration can be achieved without system redundancy and spurious long-distance well connectivity. Also, by using a more stable pressure-matching technique, we show that pressure data are better matched and reservoir volume is accurately characterized.\u0000 RGNet provides a novel hybrid physics and data-driven reservoir modeling method to fit in closed-loop reservoir management (CLRM). As RGNet models are combined with fundamental flowing physics, the calibrated model parameters are easy to interpret and understand. An RGNet model runs with far less computational cost than required by a full-physics model, which allows it to be a more practical solution to history match, predict, and optimize real assets.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"2 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86343404","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}