Day 1 Wed, March 13, 2024最新文献

{"title":"A System Identification Approach for Spatiotemporal Prediction of CO2 Storage Operation in Deep Saline Aquifers","authors":"A. Ganesh, Alireza Rangriz Shokri, Yessica Peralta, G. Zambrano, Rick Chalaturnyk, E. Nickel","doi":"10.2118/218059-ms","DOIUrl":"https://doi.org/10.2118/218059-ms","url":null,"abstract":"\u0000 Estimation of subsurface storage performance before obtaining storage credit is a key requirement in development of a CO2 sequestration hub. Traditionally, reservoir modelling tools have been used, in similar engineering applications. However, physics-based models are computationally expensive for early decision making processes, particularly in deep saline aquifers due to large geographical spread and limited geological data. In this work, we present a system identification approach to rapidly emulate the geological CO2 storage operation.\u0000 Leveraging 8 years of field performance data at the Aquistore CO2 injection site, we built non-isothermal EOS-based fluid flow simulations; multiple realizations were calibrated with periodic monitoring data of downhole injection rate, pressure, and temperature. We then tested the possibility of applying system identification techniques based on the proper orthogonal decomposition (POD). The POD models were formulated to include spatial variations in petrophysical properties, irregular boundaries, and multiple CO2 injection inputs. Additionally, we included multiple synthetic realizations of CO2 injection into saline aquifer with dependent and independent variables. The training and validation of POD models included a robust and complete data sets of the Aquistore injectivity performance at multitemporal resolutions, and time-lapse seismic surveys from the storage and overlying caprock formations.\u0000 The accuracy and efficiency of POD models were measured using multiple quantitative metrics, including global root mean squared error, training time, and forecast time. POD was found a powerful tool to reduce the spatiotemporal dimensionality of the large Aquistore dataset and to speed up the training process. It also produced acceptable global errors compared to the scale of the downhole measured responses. The infographics of the entire pressure/saturation/temperature field variations, using a set of basis vectors and time-varying coefficients, indicated that POD is capable to capture the CO2 plume shape. The visualization of POD predictions suggested to employ smaller grid size around the injection well for higher accuracy and larger grid size near the model boundary for higher efficiency (when generating the training set using CMG GEM simulator). The Aquistore dataset included multiple injection and shut-in periods during the past 8 years. This highlighted the significance of multi-temporal issues when the inclusion of finer time resolutions during start and end of CO2 injection improves the performance and accuracy of POD models. However, when CO2 plume extent is significantly large compared to the reservoir boundaries, the number of time steps needed proper management to keep the training process within a reasonable time.\u0000 POD-based proxy models offer huge reduction in data dimensionality and computational time. The results from our system identification approach using the Aquistore field data deliver insigh","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284768","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Pore-Scale Evaporative Drying, Salt Precipitation and Crystallization Migration in CO2 Injection Process by a Lab-On-A-Chip System","authors":"Bo Wang, Xiangzeng Wang, Quansheng Liang, Yuanhao Chang, Rui Ma, Zeyu Lin, Xinqian Lv, Yishu Li, Fanhua Zeng","doi":"10.2118/218048-ms","DOIUrl":"https://doi.org/10.2118/218048-ms","url":null,"abstract":"\u0000 In this study, a self-designed microchip system was used to visually study the pore-scale salt crystallization and migration, and a high-performance optical microscope was used to dynamically observe the salt precipitation process and results. The results show that pore-scale salt crystals mainly precipitate in the residual water phase, and mainly present two forms of occurrence, large-grained salt crystals and small-grained aggregated crystals, respectively. In addition to growing in the brine phase, large-grained salt crystals also nucleate and grow at the gas-liquid interface, and the maximum salt crystal size can reach the order of the pore size. This phenomenon was discovered for the first time and has not been mentioned in the existing literature. In addition, this study also observed an interesting phenomenon. The salt crystals formed in the wetting brine film and the brine phase can migrate under the combined influence of displacement pressure and capillary force, and eventually accumulate and precipitate inside the pores. Injection flow rate and salinity have a strong influence on the pore-scale salt crystallization kinetics. There is a critical value for the injection flow rate, and the critical injection rate causes the salt precipitation to be significantly aggravated. Under the same injection flow rate, an increase in salinity leads to an increase in the amount of salt precipitation.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"8 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395938","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Dielectric Property Measurements in Frequency Domain of Water Saturated Clean and Oil Sands at Elevated Thermobaric Conditions","authors":"I. Kuznetcov, A. Kantzas, S. David","doi":"10.2118/218044-ms","DOIUrl":"https://doi.org/10.2118/218044-ms","url":null,"abstract":"\u0000 Electromagnetic (EM) irradiation is a relatively nascent, but promising oil recovery method. It is well-positioned to enable carbon-free oil production from heavy oil- and bitumen-rich formations. Unfortunately, this method has not been widely adopted yet due to a lack of understanding of the dielectric properties of oil-bearing rocks at elevated thermobaric conditions. The present work aims to bridge this gap by conducting dielectric property frequency spectra measurements of heated and pressurized \"native\" core samples.\u0000 A patented system was commissioned and a series of dielectric measurements of saturated oil sand core samples were performed in two successive heating-cooling cycles within the 20°C to 220°C range. The pore pressure was kept constant above steam saturation point for the first cycle and was purged by the second cycle’s end to induce evaporation. Moreover, every measured sample was compacted by a load of 1000 psi (6.89 MPa). In addition, a comprehensive database management system was designed to facilitate automatic data acquisition of the time- and temperature-series of the relative dielectric constant and conductivity frequency responses.\u0000 The relative dielectric constant and the conductivity frequency spectra were found to be directly proportionate to temperature with some level of hysteresis between the heating and cooling cycle trends. To better visualize and interpret this behavior, three-dimensional maps of the dielectric properties in frequency-temperature domain were constructed. Singularities were observed in the results for the saturated clean and oil sand samples at certain resonant frequencies. Those frequencies signify extremums in the EM energy transfer to the formation. Increased values in the relative dielectric constant and decreased values in the conductivity at frequencies smaller than 1 MHz were attributed to the electrode polarization effect, which becomes more prominent at higher temperatures and concentration of dissolved solids. In all heating experiments of water saturated clean sands a full evaporation of the pore fluid was achieved, and the dielectric properties would approach the properties of air. However, no steam desiccated zones were observed in the oil sand samples. As a result, the local concentration of ions, minerals and other solids present in the pore fluid increased, which was further confirmed by the increase in the measured dielectric properties.\u0000 To the best of the authors’ knowledge this was the first time the dielectric measurements of \"native\" oil sand sample cores that make up most heavy oil- and bitumen-bearing formations in Athabasca region, were performed in variable temperature-pressure-steam quality environments. These measurements should provide better means to modelling of electromagnetic energy dissipation in different parts of the formation and forecasting oil production by relevant EM heating methods.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"29 10","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284745","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrating Fracture and Reservoir Modelling to Evaluate Fracture Geometry and Reservoir Performance – A Duvernay Case Study","authors":"Robert Stewart Taylor, Kevin Joslin, Neal Alexander, Jared Jackson","doi":"10.2118/218073-ms","DOIUrl":"https://doi.org/10.2118/218073-ms","url":null,"abstract":"\u0000 Hydraulic fracture modelling and reservoir simulation modelling both have many benefits for understanding the performance of induced fractures and the reservoir. However, these modelling practices are rarely used together. By integrating these workflows, it enables a more comprehensive and accurate understanding of how both primary and complex induced fractures contribute to production. In this study, a Duvernay case history was investigated where fracture and compositional reservoir simulation were both applied as one integrated workflow.\u0000 Initially the two workflows were conducted independently. The complete pumping schedule was used in a fracture simulator to predict the number, size, shape, and conductivity of the hydraulic fractures. To properly characterize reservoir flow with a gas-condensate fluid system having complex phase behaviour, a compositional reservoir simulator was required. The reservoir simulation model was history matched against field production data to determine which fractures were contributing to production. Following the history match, new fracture designs were evaluated in the fracture treatment software to better improve cluster and stimulation efficiency. These second- generation optimized fracturing treatment designs were then evaluated in the reservoir model in an iterative process to determine the impact more accurately on production rates, decline curves, and resulting cumulative production.\u0000 While fracture modelling provided detailed predictive capability for fracturing treatment design, compositional reservoir production matching contributed a new level of understanding to determine which fractures were contributing to production. The use of reservoir modelling for production matching provided a methodology of reverse engineering the most likely average values for fracture half length, number of effective fractures contributing to flow, and fracture conductivity. A new optimal fracture treatment design was developed by designing it in the fracturing software and evaluating the performance in the reservoir simulator.\u0000 This integrated workflow provides insights into limitations of the fracturing treatment design pumped, and what further predictive fracture modelling should be undertaken to further optimize future treatments. The net result provides operators with a new opportunity for increased production and profitability.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"99 12","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395485","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Characterization of Wormhole Growth and Propagation Dynamics During CHOPS Processes by Integrating Rate Transient Analysis and a Pressure-Gradient-Based Sand Failure Criterion in the Presence of Foamy Oil Flow","authors":"Liwu Jiang, Jinju Liu, Tongjing Liu, Daoyong Yang","doi":"10.2118/218027-ms","DOIUrl":"https://doi.org/10.2118/218027-ms","url":null,"abstract":"\u0000 Characterization of the wormhole growth and propagation dynamics has been made possible with the semi-analytical models developed in this work by integrating both rate transient analysis (RTA) and a pressure-gradient-based (PGB) sand failure criterion in the presence of foamy oil flow. As for the theoretical RTA models incorporated with a PGB sand failure criterion and foamy oil properties, the nonlinearity caused by the latter is linearized by using the pseudofunctions. A sequential method is adopted to solve the coupling fluid-solid problem, while the source function and finite difference methods are applied to obtain the solutions for fluid flow in the matrix and wormhole subsystems, respectively. New wormhole segments can be generated once the PGB sand failure criterion has been achieved, while their updated petrophysical properties conditioned to the new pressure field can be sent back to obtain the solutions for the fluid flow in the next time interval. Furthermore, influence of sand failure/fluidizing and foamy oil properties on the dynamic wormhole network can be investigated with the generated type curves. Both wormhole growth and foamy oil flow dictate an upward fluid production at the early times, while the production-induced pressure depletion dominates the declining production at the late times. The fractal wormhole networks can be dynamically characterized by history matching the field fluid and sand production profiles. Both the sand failure degree and foamy oil properties dictate the effective wormhole coverage and intensity. Sand production is found to be influenced by both the breakdown pressure gradient and wormhole conductivities, while oil production rate can be dominated by the wormhole coverage and intensity. Foamy oil flow can increase oil production rate and increase the wormhole coverage compared with the conventional oil. The newly developed method in this work has been validated and then applied in field-scale to dynamically characterize the wormhole growth and propagation by considering both sand failure phenomenon and foamy oil properties within a unified, consistent, and accurate framework. In this work, a rigorously semi-analytical method has been proposed to dynamically characterize the wormhole growth and propagation for the first time by incorporating the RTA, PGB sand failure criterion, and foamy oil properties. Compared to the conventional numerical simulations, not only is this proposed method accurate for wormhole characterization conditioned to fluid and sand production profiles, but also such delineated wormholes can be readily integrated with any reservoir numerical simulators to assess and optimize any potential EOR methods in post-CHOPS reservoirs.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"15 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395713","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Making Better Wells with Autonomous Inflow Control Valves for Water Control in the Flank of the Bretaña Norte Oilfield, Peru. A Case Study.","authors":"W. Garcia, A. Zegarra, E. Bustamante, A. A. Uzcategui, M. Roa, S. Fipke","doi":"10.2118/218074-ms","DOIUrl":"https://doi.org/10.2118/218074-ms","url":null,"abstract":"\u0000 Making better wells is paramount to provide better reservoir drainage, achieve higher oil production and improve recovery factors, while supporting Oil and Gas (O&G) companies in meeting their emissions reduction goals. Reservoir management is one the most impactful areas to reduce CO2 emissions and target lower carbon oil in the O&G industry, particularly for heavy oil fields with water drive mechanisms where significant energy consumption is related to unwanted water production, treatment, and reinjection. In the last decade, several operators in South America have applied various inflow control technologies to tackle this challenge.\u0000 Bretaña Norte is a heavy-oil greenfield located in a remote area of north-east Peru (18-19 °API and 25 cP). After a few initial appraisal wells, the field development strategy was designed around horizontal wells and advanced completions with autonomous inflow control devices (AICD). The presence of a bottom aquifer provides a water drive mechanism with strong pressure support, but it causes water production to reach unacceptable levels, negatively impacting oil production and CO2 footprint. As a part of a technology evaluation program, the Autonomous Inflow Control Valve (AICV) technology was selected for field trials due to its ability to autonomously shut-off water, based on the fluid properties. A reservoir simulation study was conducted, and its expected performance was compared to other AICD technologies installed in the field, indicating potential benefits related to better reservoir management.\u0000 The AICV completion was installed in a horizontal well placed in the lower flank of the reservoir structure which was deemed a challenging well position due to its proximity to the oil-water contact. After the initial well clean-up, the well began production with 2% BSW (basic sediments and water) and increased as expected until it reached 50%, where a change in slope of the BSW% trend was noted, suggesting that the AICV started to control the water influx. Total fluid production rate remained very stable with the ESP pump frequency held at the minimum speed. Another change in slope was noted at 70% when the well entered a water-cut stabilization phase. A ramp-up phase started after 1 year of production at 80% BSW, which illustrated the selective choking capabilities of the technology as the water cut has stabilized to maintain steady oil production. Production results have accurately matched initial forecasts obtained in the simulation study. Based on more than two years of production results, the AICV well has outperformed all other technologies installed in the right flank of the oil field. Production trends indicate that the cumulative oil production of the AICV well will be >15% higher after 475 days of production compared to other AICD wells, while drastically reducing the water production by more than 55% in the same production period (>3,500 MBbl). These results clearly demonstrate the added value of the ","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"69 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284764","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Introducing a New Hybrid Data-Physics Architecture for Production Forecasting in Unconventional Wells","authors":"R. Matoorian, M. Malaieri, R. Shor, R. Aguilera","doi":"10.2118/218111-ms","DOIUrl":"https://doi.org/10.2118/218111-ms","url":null,"abstract":"\u0000 This research presents a new architecture and implementation to overcome inherent challenges in leveraging machine learning (ML) for evaluating production performance in unconventional wells. By implementing a hybrid data-physics architecture (HDP), our goal is to effectively address several persistent hurdles, including generalizability limitations across diverse samples, the necessity for extensive training datasets, and the discrepancies between model predictions and fundamental physical principles. These fundamental constraints form the focal points of our comprehensive investigation.\u0000 This new HDP architecture seamlessly integrates a physics-based equation into the framework of a deep neural network model. The training dataset encompasses a wide array of influencing factors on production rates, encompassing information that may not readily conform to conventional physical equations. This sophisticated approach enables the inclusion of supplementary data, thereby significantly enhancing the precision of production forecasts. As a result, these data points are adeptly employed to derive the model's underlying physical parameters, leading to highly accurate production rate calculations. Once these parameters are estimated with minimal error, the trained model exhibits exceptional proficiency in forecasting both short-term and long-term production rates consistently.\u0000 To thoroughly evaluate the efficacy of the developed architecture, an extensive assessment was conducted using unconventional wells situated in the Duvernay resource within the western Canadian sedimentary basin (WCSB). This evaluation spanned three different methodologies to compute future production rates: with physical decline curve equations including Arps, Power Law, and Duong, with data-driven modeling where production rate forecasted with different powerful ML techniques including Random Forest, Ada-Boost, and K-Nearest Neighbors, and finally with HDP modeling. The results compared with different statistical metrics across all evaluated scenarios, the hybrid model consistently exhibited superior precision in production forecasting.\u0000 A noteworthy advantage intrinsic to the new hybrid architecture is its remarkable capacity to generate more accurate predictions without requiring extensive sample points for training. This characteristic proves especially advantageous for newly established wells with limited production histories. Moreover, the predictive outcomes yielded by the hybrid model demonstrate a strong alignment with fundamental physical models, thereby validating its applicability across both short-term and long-term production forecasting contexts.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"33 S123","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140395082","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Scaled Physical Modeling of Cyclic CO2 Injection in Unconsolidated Heavy Oil Reservoirs Using Geotechnical Centrifuge and Additive Manufacturing Technologies","authors":"Daniel Cartagena Perez, Alireza Rangriz Shokri, G. Zambrano, Dymtro Pantov, Yazhao Wang, Rick Chalaturnyk, Chris Hawkes","doi":"10.2118/218047-ms","DOIUrl":"https://doi.org/10.2118/218047-ms","url":null,"abstract":"\u0000 The success of CO2 injection in shallow reservoirs such as CHOPS (Cold Heavy Oil Production with Sands) entails an understanding of the complex interplay of mechanics of gaseous solvent interaction, reservoir deformation, and borehole collapse. This paper provides the design of a highly-instrumented scaled laboratory experiment inside a 2-meter radius beam geotechnical centrifuge, capable of simulating the cyclic CO2 injection into an unconsolidated sandstone specimen at reservoir conditions.\u0000 Given that sand production during CHOPS creates high-permeability channel-like structures, additive manufacturing technology (i.e. 3D printing with actual sand particles) was used to fabricate the physical model specimen of a scaled reservoir. A centrifuge cell was designed and constructed to simulate the multi-phase cyclic CO2 injection process at the reservoir scale. Scaling factors for stress, time, height and density were used to determine the centrifuge operation. A loading system was included in the centrifuge cell to emulate the vertical stress from the overburden rocks at the top of a shale caprock layer. Stress anisotropy in horizontal stresses were applied through an 8-arm horizontal loading system, similar to a true triaxial cell. A sand trap and a production unit were used to collect the collapsed sands and the produced fluids.\u0000 To establish residual water saturation, the reservoir prototype was first saturated with water, followed by dead canola oil and live oil (prepared by dissolving CO2). The experiment was started by spinning the 500 kg setup inside the geotechnical centrifuge until it reached a steady rotational speed of 120 revolutions per minute (equivalent to 30 times the gravitational acceleration). The perforations of a scaled wellbore within the reservoir prototype were opened to initiate fluid and sand production. It appeared that the increase in the cohesion of the 3D printed rock in regions away from wellbore reduced rock failure during production cycles even with large seepage forces and pressure gradients. The structural changes around high-permeability zone and near-wellbore region were related to stress concentration.\u0000 The result of our scaled physical experiments delivers insights on fluid displacement and rock deformation during CO2 saturated oil production from a reservoir prototype. The application of a geotechnical centrifuge and additive manufacturing technology provides a platform to experimentally explore the multi-scale, multi-physics processes of sampling, flow, and deformation issues observed in subsurface systems including H2 storage and safe disposal of radioactive waste.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"45 S212","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140394989","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Advanced Characterization and Gas Enhanced Oil Recovery in Tuscaloosa Marine Shale","authors":"F. O. Yisa, B. D. Saikia, D. N. Rao","doi":"10.2118/218040-ms","DOIUrl":"https://doi.org/10.2118/218040-ms","url":null,"abstract":"\u0000 This work experimentally determines the viability of enhanced oil recovery (EOR) by gas injection in core samples from Tuscaloosa Marine Shale (TMS) while investigating the effects of gas type, rock dimension, EOR modes and rock brittleness on the EOR performance. TMS is a promising play in Louisiana with estimated reserves of 7 billion barrels of oil. Experimental studies on EOR performance in several shale plays exist but none have been performed to study its viability in TMS.\u0000 An Eagle Ford sample with dimensions 1.0-inch diameter by 1.0-inch length, TMS cores with dimensions 1.0-inch diameter by 1.0-inch length, 1.0-inch diameter by 2.0-inchlength, and 1.5-inch diameter by 3.0-inch length from 5 wells were used for this study. The cores were cleaned prior to vacuuming and saturation with TMS oil. The coreflood experiments were run at a pressure of 2000 psi and temperature of 70°F. Nitrogen (N2) and carbon dioxide (CO2) were used as injectants for the enhanced oil recovery (EOR) experiments. X-ray Diffraction (XRD) was used to determine the mineralogical content of the TMS core plugs.\u0000 XRD tests show the fractured cores contain carbonates (5% to 50%) including quartz which makes the rock brittle and more favorable to complex fractures desirable for maximizing recovery in shales, while carbonates are absent in the unfractured cores. Samples E have fractures with higher wt% of quartz and carbonate but lower wt% of clay compared to samples B, C and L. The study shows gas EOR is promising in TMS with CO2 EOR recovery within 22% - 26% compared to N2 EOR recovery within 18% - 19.76%. Gas Assisted Gravity Drainage (GAGD) continuous mode showed higher recovery than GAGD Huff-n-Puff. The ratio of quartz/carbonates to clay in B and C (1.22 - 2.51: 1) was lower compared to the ratio in E (6:1) which explains why B1, B2 and C2 (1.0-in diameter by 2.0-incu length) did not disintegrate prematurely during the experiments compared to E1 with equal dimension. The samples with larger pore volumes, like EL1 (1.5-in diameter by 3.0-in length) displayed more structural integrity than E1(1-in diameter by 2-in length) which disintegrated during its 2nd experiment.\u0000 This study shows the potential of gas EOR in TMS shale which is insightful as CO2 sequestration has now become increasingly important. It identifies sweet spots for further exploitation and demonstrates the importance of mineralogical content in geomechanical properties in successfully planning EOR experiments. This extends to field applications of EOR. Furthermore, it reveals important findings regarding optimum saturation periods for shale cores in EOR experiments.","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"53 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284655","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Modelling of Production and Fiber Optic Data for Analyzing Inter-Well Interactions in Fractured Shale Gas Reservoir","authors":"Chuanyao Zhong, Jiahui Chen, Juliana Y. Leung, M. van der Baan","doi":"10.2118/218066-ms","DOIUrl":"https://doi.org/10.2118/218066-ms","url":null,"abstract":"\u0000 Fiber optic techniques, including Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS), enable real-time monitoring and interpreting of fracture hits, stress shadowing, and production behavior. However, integrating field DTS/DAS data and production responses remains challenging. This work uses numerical simulation to model fracture propagation, stress evolution, and fluid production in a shale reservoir. The capability of the numerical model to address these coupled flow-geomechanical issues is systematically evaluated. The simulation responses are analyzed to understand various observations extracted from some field DTS/DAS data. While previous coupled flow-geomechanical simulation studies have compared their numerical results of fracture hits to DAS responses, few studies have examined how the observed fracture interference would affect the fracture development and production performance of other nearby well drilled subsequently (e.g., child well). There are even fewer attempts to incorporate DTS data when analyzing the production performance of these offset wells.\u0000 Detailed mechanistic models are constructed to simulate various fracture hits and crossflow scenarios. 3D thermal flow models with wellbore modelling are coupled with geomechanical calculations. Multi-scale fracture responses are modelled, e.g., physical opening/closure of hydraulic fractures (HF), induced secondary fractures, and pre-existing natural fractures. A commercial simulator is used, a systematic examination of most available model setup options was performed to achieve the most accurate responses in the flow-geomechanical simulations. Two novel features are added: first, the apparent permeability of the matrix is updated based on pore pressure to capture the effects of nano-scale flow behaviors; next, natural fracture properties are updated based on the computed stress, capturing their closure/dilation. Several field cases based on the Montney Formation are replicated. Simulated strain rate and temperature responses are compared to field DAS/DTS and production data provided by an industrial partner.\u0000 Simulation results reveal that while fracture hits and stress shadowing hinder the development of adjacent new fractures, they also boost the production of nearby stages, especially in the early phases. Frac hits lead to slower cooling during injection and faster warm-back during shut-in and flowback near the wellbore; they additionally induce unforeseen temperature reductions in areas devoid of any newly stimulated fractures, this demonstrates that DTS can detect the effects of fracture hits and crossflows in real time during treatment. These effects intensify with closer proximity but diminish with higher intensity of frac hits.\u0000 For the first time, optimal model configurations have been introduced that are designed for deployment within the commercial software package to achieve precise simulations of the hydraulic fracturing process. A quantitati","PeriodicalId":517523,"journal":{"name":"Day 1 Wed, March 13, 2024","volume":"119 20","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-03-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140284986","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}