Day 2 Tue, April 18, 2023最新文献

{"title":"Optimization of Child Well Hydraulic Fracturing Design: A Bakken Case Study","authors":"A. Merzoug, Abdulaziz Ellafi","doi":"10.2118/213060-ms","DOIUrl":"https://doi.org/10.2118/213060-ms","url":null,"abstract":"\u0000 The combination of hydraulic fracturing and horizontal drilling unlocked a huge energy potential in the US. The unconventional plays have been developed by drilling several horizontal wells and hydraulically fracturing them to enhance the fluid flow. The implementation of these well can be done at the same time, known as Tank Development; however, due to the high capital expenditure and the increased risks associated with such an approach, in addition to the limited number of available drilling rigs. Operators try to hold the lease first by drilling one well, producing it, then extending the lease with additional wells. The challenge is that by producing from these wells, the stress and pore pressure state changes around the first wells (i.e., parent well). These changes directly affect the hydraulic fracture propagation from the offset wells (i.e., child wells). In this work, we build a numerical that represents a real case study. The model was calibrated using data from (a) Microseismic Depletion Delineation, (b) Microseismic events, (c) 10 years of production. Synthetic offset wells were implemented to run a sensitivity analysis on the well design (well spacing, cluster spacing, injection volume) and to understand how to design better wells that have been influenced by production from a primary well. The simulations were run for 10 years. The results show that wider well spacing results in better production, whereas lower cluster spacing had better production. This study allows operators to design better offset wells drilled next to a depleted parent well in the Bakken.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124860307","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":"Application of Machine Learning to Evaluate the Performances of Various Downhole Centrifugal Separator Types in Oil and Gas Production Systems","authors":"Laura Camila Osorio Ojeda, Michael Olubode, H. Karami, Tony Podio","doi":"10.2118/213059-ms","DOIUrl":"https://doi.org/10.2118/213059-ms","url":null,"abstract":"\u0000 Pumping artificial lift techniques, such as rod pumps and ESPs, are applied for gassy wells more than ever before. This has made the downhole separators a critical part of most such installations. There are multiple categories of downhole separators, with various techniques developed to assess and improve their performances, but no general guidelines are established for their application. This paper aims to classify the separator types and review their performances in the open literature. In addition, various data sets are collected and put together to evaluate and rank downhole centrifugal separators using data analysis and machine learning (ML) techniques.\u0000 A comprehensive literature review is conducted to collect the available downhole separator performance data. Experiments and Computational Fluid Dynamic (CFD) simulations are the techniques used by the researchers. This information is collected to identify the optimum conditions for each separator type, considering the effects of liquid and gas rates and other flow parameters. The data collected from various research projects over the last 20 years are combined to make a comprehensive downhole separation databank. These data are analyzed using various machine learning algorithms to rank the performances of downhole separators at various operating conditions.\u0000 Various downhole separators have been tested in the open literature, including poor-boy separators, two-stage separators, packer-type separators, rotary and spiral separators with different designs, etc. A critical factor that adds to the uncertainty is the separator's control system, which significantly affects its efficiency. The available data show that most separators provide separation efficiencies higher than 80% if the downstream casing valve is adequately controlled. The separation efficiencies decline as the liquid and gas rates increase past an upper limit. The collected data from multiple previous studies form a broad dataset. Data analysis is used to compare the performances of different downhole separator classes, and machine learning is applied to identify a robust prediction model. This paper gathers, interconnects, and examines several available research works through data analytics. The results provide a fundamental source and a valuable guideline for downhole liquid-gas separation, particularly in artificial lift applications.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125396685","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":"Optimizing Rod Pump Performance Using High Frequency, High Resolution Pressure Data at the Wellhead","authors":"K. Vekved, T. Ito, R. Gordon","doi":"10.2118/213052-ms","DOIUrl":"https://doi.org/10.2118/213052-ms","url":null,"abstract":"\u0000 This is part of a case study designed to confirm that high frequency, high resolution pressure data measured at the wellhead of a pumpjack well can be used to evaluate and optimize the performance of the downhole pump. This paper will provide the rationale for the concepts and methods that will be used and tested during field trials of this approach.\u0000 For the field trials, participants are installing high-performance pressure monitoring devices on the tubing of rod pump wells upstream of the flow line check valve. Additional devices are being installed on the flow line. These Internet of Things (IoT) devices are rated for Class I, Division 1 hazardous zones, measure pressure at one-second intervals, and have a pressure resolution of 0.006 psi. The per-second pressure measurements are also time-synchronized and temperature-compensated for accuracy and will be delivered to a cloud-based data service over the course of several weeks.\u0000 For each well, the difference in pressure between the tubing and flow line will be analyzed in five-minute data windows. The pressure differential from each five-minute data window will provide a clear picture of the pressure the pump exerts on the flow line over the course of an average pumping cycle during that interval. Because pressure can be used as a proxy for flow, fill and efficiency at the bottom hole pump can be deduced from the calculated flow profile at surface, eliminating the rods and their associated error as the conduit of pump performance data. Assessments of pump performance using this technique will also be compared to results from production tests to determine how effective this technique is in evaluating rod pump performance. The large sample of five-minute data windows collected over the course of a month will test the technique against varying operational conditions. Furthermore, we will determine if particular pressure trends, as outlined in this paper, correlate with certain pump conditions during field trials, which would be of use for diagnosing pumping issues.\u0000 The approach of using high frequency, high resolution pressure measurement at the wellhead to assess downhole pump performance has shown promise in a previous case study (SPE-209253-MS). The current case study will add to the body of literature around this technique. Success with this technique would offer an economical alternative for monitoring rod pump performance of aging wells.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"65 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124182680","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":"Connection Fatigue Evaluation for Cyclic Dogleg Bending Events Using Fatigue Crack Growth Method","authors":"Bisen Lin, Frederick Bennett, Alexander Barnett, David Coe","doi":"10.2118/213087-ms","DOIUrl":"https://doi.org/10.2118/213087-ms","url":null,"abstract":"\u0000 Fatigue performance of OCTG threaded connections subjected to the cyclic rotational dogleg bending events during casing installation and well construction has become more and more crucial in horizontal well tubular design as its lateral becomes longer and longer for improving the well productivity. There are different methods for fatigue evaluation of structural components, such as full-scale fatigue testing and fatigue evaluation using analytic means (S-N fatigue, strain-based fatigue life, fatigue crack growth and fracture mechanics, and so on). In this paper, we implement fatigue crack growth and fracture mechanics method together with full-scale resonant bending fatigue testing for evaluating fatigue performance of OCTG connections.\u0000 The fatigue evaluation procedure consists of the following steps: First, nonlinear elastic-plastic FEA model is utilized to simulate the connection makeup to its desired makeup torque (makeup position); Second, linear elastic FEA is performed to compute the alternating stress (i.e. fatigue driving stress) and static mean stress due to makeup and/or other external constant loads; Third, fatigue crack growth of a pre-existing crack-like surface circumferential flaw at critical locations is performed for selected dogleg severity (DLS), e.g.10, 15, 20, 25, 30, and 35 deg/00ft, etc. Finally, the connection fatigue curve in terms of fatigue life (number of cycles to fatigue failure,Nf) versus DLS (in deg/00ft) is constructed.\u0000 Material parameters used in the fatigue crack growth model were calibrated to a single set of full-scale connection fatigue-to-failure tests for different DLS values on a single connection product (i.e., same OD, wall, grade, and connection design). By using this calibrated fatigue analysis model, we are able to achieve excellent agreement on the connection fatigue life for a broad range of DLS magnitudes (from 10 to 35 deg/00ft) between the analysis and the actual test results for several different connection products, i.e., different OD, different wall thickness, and different connection designs (API buttress-type thread, proprietary wedge thread, etc.). Moreover, the model is also able to predict the critical location at which a through-wall crack would develop and cause leak that are consistent with what were observed in the full-scale connection fatigue tests.\u0000 Connection fatigue evaluation by means of fatigue crack growth and fracture mechanics presented in this paper is a value-added tool to the full-scale connection fatigue testing since it is extremely time and cost effective. The fatigue analysis tool can be used to calculate the fatigue life of any threaded OCTG connections subjected to cyclic loading (e.g., rotational dogleg bending, frac cycles, and so on). For instance, it can be very beneficial for assessing fatigue performance of a new connection product design and development, especially when the connection is intended to be used in the horizontal wells with long lateral for ex","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129979255","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":"Application of Machine Learning Optimization Workflow to Improve Oil Recovery","authors":"Abdul-Muaizz Koray, Dung Bui, W. Ampomah, Emmanuel Appiah Kubi, Joshua Klumpenhower","doi":"10.2118/213095-ms","DOIUrl":"https://doi.org/10.2118/213095-ms","url":null,"abstract":"\u0000 Machine learning application in the oil and gas industry is rapidly becoming popular and in recent years has been applied in the optimization of production for various reservoirs. The objective of this paper is to evaluate the efficacy of advanced machine learning algorithms in reservoir production optimization.\u0000 A 3-D geological model was constructed based on permeability calculated using a machine learning technique which involved different architectures of algorithms tested using a 5-fold cross-validation to decide the best machine learning algorithm. Sensitivity analysis and a subsequent history matching were conducted using a machine learning workflow. The aquifer properties, permeability heterogeneity in different directions and relative permeability were the control variables assessed. Field development scenarios were exploited with the objective to optimize cumulative oil recovery. The impact of using a normal depletion plan to a secondary recovery plan using waterflooding was investigated. Different injection well placement locations, well patterns as well as the possibility of converting existing oil producing wells to water injection wells were exploited. Considering the outcome of an economic analysis, the optimum development strategy was realized as an outcome for the optimization process. Prior to forecasting cumulative oil production using artificial neural network (ANN) for the optimization process on the generated surrogate model, a sensitivity analysis was performed where the well location, injection rates and bottomhole pressure of both the producer and injector wells were specified as control variables. The water cut as part of the optimization process was utilized as a secondary constraint. Forecasting was performed for a 15-year period. The history-matching results from the constructed geological model showed that the oil rate, water rate, bottom hole pressure, and average reservoir pressure were matched within a 10% deviation from the observed data. In this study, the ANN optimizer was found to provide the best results for the field cumulative oil production. Using a secondary recovery development plan was observed to significantly increase the cumulative oil production. A machine learning based proxy model was built for the prediction of cumulative oil production to reduce computational time. In this study, we propose an approach applied to reservoir production optimization utilizing a machine learning workflow. This was accomplished by utilizing a surrogate model which was calibrated with a number of training simulations and then optimized using advanced machine learning algorithms. A detailed economic analysis was also conducted showing the impact of a variety of field development strategies.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129285797","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":"Optimizing Artificial Lift Timing and Selection Using Reduced Physics Models","authors":"Hardikkumar Zalavadia, M. Gokdemir, Utkarsh Sinha, S. Sankaran","doi":"10.2118/213089-ms","DOIUrl":"https://doi.org/10.2118/213089-ms","url":null,"abstract":"\u0000 Unconventional field production relies heavily on artificial lift, but with reservoir energy depleting, lifting hydrocarbons efficiently and economically is one of the challenging parts of field development. Traditional lift selection methods are insufficient for managing unconventional wells with high initial decline rates. Understanding how production behaves under various lift conditions is crucial because lift method timing and design are the most important considerations for optimizing well performance. In order to increase the value of unconventional oil and gas assets, this paper presents an artificial-lift timing and selection (ALTS) methodology that is based on a hybrid data-driven and physics-based workflow.\u0000 Our formulation employs a reduced physics model that is based on identification of Dynamic Drainage Volume (DDV) using commonly measured data (flowback, daily production rates, and wellhead pressure) to calculate reservoir pressure depletion, transient productivity index (PI) and dynamic inflow performance relationship (IPR). Transient PI as the forecasting variable normalizes both surface pressure effects and takes phase behavior into account, reducing noise. For any bottom hole pressure condition, the PI-based forecasting method is used to predict future IPRs and, as a result, oil, water, and gas rates. The workflow calculates well deliverability under various artificial lift types and design parameters.\u0000 The ALTS workflow was applied to real-world field cases involving wells flowing under various operating conditions to determine the best strategy for producing the well among several candidate scenarios. The results of transient PI and dynamic IPR provided valuable insights into how and when to select different AL systems. The workflow is run on a regular basis with ever-changing subsurface and wellbore conditions against each candidate scenario using different pump models and other operating parameters (pressure, speed etc.). The method was applied in hindcasting mode to several wells to evaluate lost production opportunity and validate the results. In some cases, the best recommendation was to use a different artificial lift system than the one used in the field to significantly improve long-term well performance. Furthermore, optimal artificial lift operating point recommendations for wells are made, including optimal gas lift rates for gas lifted wells, optimal pump unit selection and speed for ESP and SRP wells.\u0000 The proposed method predicts future unconventional reservoir IPR consistently and allows for continuous evaluation of artificial lift timing and selection scenarios in unconventional reservoirs with multiple lift types and designs. This has the potential to shift incumbent practices based on broad field heuristics, which are frequently ad hoc, inefficient, and manually intensive, toward well-specific ALTS analysis to improve field economics. Continuous use of this process has been shown to improve production, red","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127074627","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, Superior Shale Oil EOR Methods for the DJ Basin","authors":"R. Downey, K. Venepalli, J. Erdle","doi":"10.2118/213082-ms","DOIUrl":"https://doi.org/10.2118/213082-ms","url":null,"abstract":"\u0000 According to Novi Labs, a well data analytics company, as of April, 2022, 94,000 horizontal shale oil wells had been placed into production in the 5 major US shale oil basins. Oil production from these wells is characterized by high initial rates and steep declines, with well lives of 9 to 16 years. Oil recovery factors, as a percentage of oil in place, range from 2.5 to 8 percent, leaving the vast majority of oil resources unrecovered. Shale oil EOR is in its infancy, with only 49 permitted projects involving a few hundred wells. 36 of these EOR projects are in the Eagle Ford shale. Prior publications have provided information on this activity, almost all of which involve cyclic injection of natural gas, or Huff-n-Puff EOR. Incremental recoveries have been projected to range from 10% to 80% of primary EUR.\u0000 Our objective is to describe two novel shale oil EOR methods that may provide superior incremental shale oil recovery of 100 to 200% of primary EUR in the DJ Basin Niobrara shale. We have developed two superior shale oil EOR methods that utilize a triplex pump to inject a liquid solvent mixture into the Niobrara shale reservoir, and methods to fully recover the injectant at the surface, for storage and reinjection. The processes are fully integrated with compositional reservoir simulation to optimize the recovery of residual oil during each injection and production cycle.\u0000 Compositional reservoir simulation modeling of the processes in a production and pressure history-matched horizontal DJ Basin Niobrara well indicates recoveries of 180% to 360% of primary EUR may be achieved. These processes have numerous advantages over cyclic gas injection - shorter injection time, faster and greater oil recovery, lower risk of interwell communication, lower cost of production, elimination of the need for artificial lift, and lower GHG emissions and water costs. These processes should work in all US shale oil plays, and have been successfully field tested in some. If implemented early in the well life, their application may enable recovery of more oil, faster, and preclude the need for artificial lift, resulting in shallower decline rates and much greater reserves. The processes also emit less GHG emissions and have lower water costs per barrel than primary recovery.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124916897","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":"Numerical Simulation of In-Situ CO2 Mineralization in Mafic Basaltic Formations in Southwest Oklahoma","authors":"Qais Al Maqbali, Sadam Hussain, G. Mask, Wu Xingru","doi":"10.2118/213084-ms","DOIUrl":"https://doi.org/10.2118/213084-ms","url":null,"abstract":"\u0000 Power plants and other industries in Oklahoma produce a huge amount of CO2 emissions that should be mitigated for environmental benefits. One method to mitigate these emissions is permanent CO2 sequestration through mineralization. CO2 can be mineralized in the subsurface if injected into iron- magnesium-rich igneous formations that form carbonate minerals. In Southwest Oklahoma, there are several mafic basaltic formations that can be targeted for CO2 storage. The objective of this study is to quantify carbon storage through mineralization in Southwest Oklahoma.\u0000 In this study, we built a carbon sequestration numerical model to simulate the geochemical reactions of injecting CO2 into a saline aquifer. The model includes three main geochemical reactions: CO2 dissolution in water, dissolution of formation minerals, and precipitation of carbonate minerals. The first reaction results in forming carbonic acid that reacts with the formation minerals: anorthite, wollastonite, pyroxene, and olivine, which results in releasing calcium and magnesium ions. The reaction between free ions in the formation of water and dissolved CO2 results in precipitating carbonate minerals: magnesite and calcite. CO2 is injected into the formation for four years and simulated for the next 200 years. The rate of dissolution and precipitation was monitored as a function of time. In addition, the reservoir parameters: porosity, permeability, and reservoir pressure, were analyzed as a function of time and precipitation rate.\u0000 The results show that 97% of the injected CO2 is mineralized, and the rest is residually trapped and dissolved in water. Due to the mineralization of CO2 in the form of magnesite, and calcite, the porosity decreased by 5% maximum due to the extra cement in the pore space. The reservoir pressure increases during the injection, but it decreases rapidly after due to the quick CO2 mineralization. Lower reservoir temperature increases the amount of CO2 mineralized due to the higher CO2 solubility in water. In addition, changing the activation energy of mineral reactions leads to a change in the dynamics of CO2 mineralization, but the net of CO2 mineralization changes slightly.\u0000 The carbon storage numerical model built for this study considers the effect of the formation water chemistry and rocks mineralogy on the amount of CO2 sequestrated. In addition, it shows that Oklahoma can lead to carbon sequestration in basaltic formations.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124801565","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":"Geomechanical Study and Wellbore Stability Analysis for Potential CO2 Storage into Devonian and Silurian Formations of Delaware Basin","authors":"S. Nguyen, T. Nguyen, H. Yoo, G. El-kaseeh","doi":"10.2118/213073-ms","DOIUrl":"https://doi.org/10.2118/213073-ms","url":null,"abstract":"\u0000 The objective of this project is to construct a 1D mechanical earth model for the prospective geological sequestration of carbon dioxide (CO2) into carbonate formations. The study sustains a pivotal role in analyzing the possible wellbore instabilities for drilling deep injection wells. Besides, the developed model can be essentially used to evaluate the caprock integrity for long-term CO2 storage and provide the primary analytical assessment of fault slip potential.\u0000 This paper describes the extensive construction of a geomechanical model to achieve three ultimate goals. A variety of petrophysical interpretations, shear wave velocity modeling, and Mogi-Coulomb failure criterion are initially established to deliver a safe drilling mud weight window for overpressure ramps in the Delaware basin, a sub-basin of the Permian. Using the dependable outputs of rock properties and strengths, top seal quality is subsequently determined by calculation of the brittleness index and critical pressure of tensile failure. Finally, pore pressure, shear stress, friction angle, and in-situ stresses are integrated to predict maximum sustainable injection pressures for preliminary fault slip analysis in deep aquifer carbonate rocks.\u0000 Two distinct overpressured zones of Wolfcamp and Barnett Shale are identified for wellbore instability based on pore pressure and fracture gradient prediction. These pressure ramps have a lower compressive strength, which causes the collapse pressure to exceed the pore pressure and serve as the lower bound of drilling mud weight. The wellbore stability simulation also shows low brittleness indices and high threshold breakdown pressures for Woodford shale caprock. It implies that the caprock may be more resistant to fracture growth and failure, indicating an effective top seal above the injected reservoirs. Meanwhile, close observation may be purposefully monitored to assess the fault slip potential in Devonian and Silurian formations once the critical injected fluid pressure approaches the projected threshold from the analytical computation.\u0000 The findings from this study will be useful in further understanding wellbore stability under drilling practices and CO2 sequestration. The appropriate application can support optimizing the casing and drilling mud weight design while also modifying the injection fluid pressure. Furthermore, the estimated rock properties, formation pressure, and principal stresses will be significant elements in building a hydrodynamic simulation of gas plume distributions after certain injection years.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"72 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115550900","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}