Day 2 Wed, January 25, 2023最新文献

{"title":"Combining Production Logging with Spectral Noise Logging and High Precision Temperature to Detect Wellbore and Behind Pipe Fractures Fluid Movement","authors":"Ali H. Alabdulmuhsin, S. Ashby, E. Terentyeva, K. Ammar","doi":"10.2118/212647-ms","DOIUrl":"https://doi.org/10.2118/212647-ms","url":null,"abstract":"\u0000 Diagnosing fractures and behind-pipe isolation is very critical to analyze production from unintended reservoirs correctly and taking proper actions. Fracture flow diagnostics using through-barrier diagnostic system is a unique solution developed to identify the positions and heights of behind pipe fractures in addition to confirming the isolation integrity between the stages.\u0000 In combination with Production logging, Spectral Noise Log (SNL) & High Precision Temperature (HPT) tool string have been running in-memory mode. Combining the technologies allowed for analyzing wellbore flow profiles by production logging. Simultaneously, SNL-HPT platform is diagnosed behind Pipe fracture flow and zonal isolations.\u0000 A well was drilled targeting three stages. After three perforation and fracturing stages, water cut increase was observed. Understanding fracture network behind pipe and across the perforations, analyzing zonal isolation, and finding true flow geometry on the \"well–formation\" system is now the critical objective of the diagnostics survey.\u0000 SNL-HPT platform under fracture flow diagnostics results, reveal behind pipe conditions accurate picture. Actual positions of active fractures behind and across each perforation stage and active reservoir zones of the non-fractured stage are correctly identified. As well isolations conditions between stages are determined and flow geometry inside the borehole and behind the pipe is provided.\u0000 By combining the SNL-HPT platform diagnostics with production logging results, the source of the high water cut caused by fracture extension was successfully identified. Isolation's decisions are properly taken and well set for production.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"113 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120914501","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":"CCUS Numerical Simulation Technology and its Application in a Carbonate Reservoir of the Middle East","authors":"Qiaoyun Li, Shuhong Wu, Han Jia, Baohua Wang, Xili Deng, Hua Li, T. Fan, Mingyuan Xu","doi":"10.2118/212634-ms","DOIUrl":"https://doi.org/10.2118/212634-ms","url":null,"abstract":"\u0000 Carbon dioxide Utilization and storage technology (CCUS) plays an important role for oil and gas field to further improve oil and gas recovery and achieve the goal of \"double carbon\" in recent years. Numerical simulation is an essential means for reservoir engineers to study the flow mechanism of CO2 flooding and storage, screen the CCUS technical indicators, predict the enhanced oil recovery and evaluate storage potential. This paper discusses the multiphase and multicomponent mathematical model based on the seepage theory of carbon dioxide flooding and storage, the calculation method of gas-liquid equilibrium based on EOS equation, the miscibility determination technique and two phase P-T flash calculation method. Meanwhile the CCUS numerical simulator developed based on above theoretical model and calculation method. Applying the simulator to CO2 miscible flooding in a carbonate reservoir of the Middle East, the results show that the model and software accurately describes the CO2-EOR seepage mechanism and CO2 miscible displacement process. It effectively predicts the effect of CO2 injection on EOR and the storage potential after CO2 flooding. It can provide feasible technical guidance for the optimization of CO2 utilization and storage programs.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124495345","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":"Advantages of Automated Rock Type Adjusting History Matching Workflow Driven by Adjoint Approach with Sensitivity Analysis of Different Model Parameters and Saturation Functions","authors":"B. Jenei, R. Manasipov, H. Almuallim, L. Ganzer","doi":"10.2118/212616-ms","DOIUrl":"https://doi.org/10.2118/212616-ms","url":null,"abstract":"\u0000 During history matching, physical inconsistencies can be introduced and remain unrevealed. A rich parameter space can mimic the historical reservoir behaviour, possibly by sacrificing geological constraints. Improved geological consistency is proposed in this work using rock-type adjustments. Sensitivity analysis of the parameters which characterise different rock types is essential. This paper demonstrates the advantages and sensitivities of the rock-typing workflow when coupled with an adjoint-based approach through various history-matching cases. In order to analyse the effect of individual model parameters on the rock-type driven history matching workflow, three different realisations of a quarter of a five-spot model were created with nine simulation cases. The analysed and modified properties are the porosity, absolute permeability, relative permeability and capillary pressure functions. The rock-type adjusting workflow is based on a Mahalanobis distance calculation; the results are compared to the standard adjoint-based workflow. The history matching process is split into stages with corresponding objective functions, e.g. rate or pressure focus, where the switch is automatic based on preliminarily defined criteria. The rock typing workflow shows more favourable results than the standard approach. The success of rock-type adjustments (validation and correction) lies in preserving the correlations between different petrophysical properties. The automated rock typing workflow can indirectly adjust the relative permeability and capillary pressure through the rock type correction. The extended workflow's performance concerning the parameters characterising different rock types is analysed. The sensitivity analysis provides a comprehensive comparison of the significance of each model parameter on the rock type adjusting history matching workflow. The results subsequently conclude the necessity of rock type adjustments for achieving a better match in the dynamic results while better maintaining the geological constraints of the static model. Conclusively a \"smart\", well-constrained automation is beneficial for achieving maximum efficiency and quality in history matching. This paper reveals a comparison between the influence of each model parameter on the rock type adjusting history matching workflow through two different automated setup combinations. While monitoring the objective functions of the dynamic results, two geological consistency indicators were introduced. These are the Valid Rock Types (VRT) and the Valid Mahalanobis Distance (VMD), which objectively quantify the validity of the final model regarding the static model assumptions. The automated rock-typing workflow improves the quality and reliability of the history-matching procedure, honouring geological consistency. Moreover, it also enhances the convergence rate and accuracy of the match. It includes automation between the different history matching sequences, which improves fi","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124551239","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":"Case Study Artificial Intelligence (AI) Assisted Numerical Reservoir Simulations in a Mature Reservoir Under Waterflood Development in the Sultanate of Oman","authors":"Fakhriya Shuaibi, Munira Mohamed Hadhrami, A. Sheheimi, B. Agarwal, Qassim Mohamed Riyami, Mohammed Ruqaishi, N. Habsi, E. Mortezazadeh, Sina Mohajeri","doi":"10.2118/212623-ms","DOIUrl":"https://doi.org/10.2118/212623-ms","url":null,"abstract":"\u0000 PDO is transforming its field development planning by adopting digital technologies and Artificial Intelligence (AI) to improve organizational efficiency and maximize business value through swift quality decisions and an evergreen forecast. In this context, the company has approached a number of third parties to bring in solutions in this domain. In 2021 one such collaboration with 3rd party contractor to test a novel solution involving data driven AI based dynamic simulator in a mature brown fiend setting. The objective was to test the tool, the efficacy and efficiency of the process, robustness and ease of use and its utility in current setting [1].\u0000 Existing dynamic modelling workflows with conventional simulators are extremely time consuming to update and upgrade in a mature brownfield setting. These conventional and lengthy iterative process of working might leave value on the table. It is time consuming to update history match with all the extra inputs and forecast; and optimizing the development with all the input parameters within a short timeframe is always a challenge.\u0000 The process employed in this approach was based on deep learning artificial neural networks (ANN) coupled with numerical simulators and along other static model inputs. The reservoir static and the flow dynamics were used as feature parameters to train the ANN, while the historical field production was used as the target parameters. The ANN training exercise identified the most contributed static and dynamic parameters to the historical production; therefore, these main parameters were given a higher weight in production forecasting and reservoir management.\u0000 This AI-simulation method was expected to be faster, data driven and allow a faster testing of multiple development strategies in short time.\u0000 This paper outlines the experience of an AI-assisted numerical simulation approach to unlock the potential of brown oil fields in south Oman by reducing the time spent on modelling and base case anchoring. It also enables evergreen forecasting by integrating AI techniques with numerical simulation. The AI-simulation was tried in a brown field with an existing FDP generated using conventional simulation tool where >50% of the FDP propose wells have been drilled. The outcomes from the AI-simulation result were compared with conventional simulation and with Actual field performance. Optimization was also conducted to locate the sweet spots for future drilling and WRFM opportunities. This optimized workflow has the potential to enable step change improvements in time and value for brownfield development and optimization for future developments.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125107819","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":"Case Study: Successful Huff and Puff Processes in a Thick, Inclined Oil Reservoir with Compositional-Gradient","authors":"Xueqing Tang, Chun-xu Yu, Ruifeng Wang, Zhengxue Du, Hui Liu, Hui Lu","doi":"10.2118/212619-ms","DOIUrl":"https://doi.org/10.2118/212619-ms","url":null,"abstract":"\u0000 This paper presents successful huff and puff process in a thick, inclined oil pool with compositional-gradient. Jake South field in Sudan contains two sets of oil and gas accumulations. The upper major pay includes thick (net pay of 200 ft), under-saturated oil inclined zones (dip angle 15-18 degrees), with compositional variation (23.82-32.6° API) and initial GOR of 62-105 scf/STB. The lower pay covers 12 gas-condensate and light oil (36-39° API) zones. The main technical challenges are attic oil recovery and strong aquifer encroachment. The solution is that high-pressure gas-condensate, high-GOR oil and high-pressure nitrogen areto inject into low-pressure oil zones for huff and puff process and avoid early water breakthrough since start-up of field development. The related technical aspects are below: In-house studies, including solubility and viscosity reduction test, 1D and 2D visible microscopic test, and long-tube physical simulation of huff-n-puff process, confirmed that gas-condensate could dissolve into oil, resulting in foamy oil with formation volume factor of 1.23 and viscosity reduction of 50% of initial value.In-situ huff and puff process. Single tubing string with isolation packer completion is run. To exploit attic oil in high-permeability (horizontal permeability of 2,990 md, and vertical permeability of 80% of horizontal permeability) zones, gas-condensate zones and upper two-thirds of main oil ones are perforated. High-pressure gas-condensate (condensate 60.9° API) travels up the tubing, and injects into oil zones, soaks for 2-3 weeks to allow the gas to migrate up-dip from the well and to displace up-structure oil downward towards the producer, then goes back on production. After gas/condensate zones deplete, high-GOR light zones and the additional main oil zones are opened, high-GOR light-crude and high-pressure nitrogen were co-injected into main-oil zones for huff-n-puff scheme, light oil working as a solvent to dilute the remaining lower-API oil. Injection pressure and injection volume of hydrocarbon gas and nitrogen are optimized to ensure that the well could flow naturally during the puff process.Multi-well huff and puff process. Huff and puff processes were conducted simultaneously at five up-dip producers to contact new oil, the watered-out, low-productivity down-dip wells were shut-in for pressure maintenance via gas injection to mitigate water influx into the oil zones.\u0000 Field production performance illustrated that initial well production at flowing conditions from five producers ranged from 3,600 to 13,800 BOPD, with well production boosting 7- to 27-fold. The average off-take rate achieved 4.0-6.6% of OOIP per year. No early water breakthrough occurred at the prolific producers. Compositional simulation confirmed that ultimate recovery factor for oil could exceed 50%. The innovative, low-cost strategy that improves oil recovery is constructive and valuable to development of those similar oil fields.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116131168","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":"Unveiling Reservoir Architecture and Characterization Using Ultra-HD Bed Boundary Mapper","authors":"Abdullah S. Saleh, Shehri A. Sultan, G. Santoso, Huliayan Furreh Alshammari","doi":"10.2118/212683-ms","DOIUrl":"https://doi.org/10.2118/212683-ms","url":null,"abstract":"\u0000 Drilling a well in one specific layer is challenging. In the subject well, multiple zones have been determined in the target reservoir. Each zone has its own property and distribution. The objective of this paper is to unveil the reservoir architecture and formation characterization using the latest logging-while-drilling (LWD) technology in ultra-high definition boundary orientation.\u0000 The methods presented in this paper are to integrate field geological knowledge, wellbore centric LWD data (Images and Triple Combo) and Ultra High Definition Bed Boundary Mapper that extend EM measurements, which allows a better fine-tuning structure and formation resistivity interpretation around the wellbore, independent of mud type. Along with those measurements, a new resistivity inversion has been developed that computes geometrically corrected resistivity for both vertical Rv, and horizontal Rh from bed boundary locations, and formation relative dip. In addition, formation relative dips and boundary positions from the inversion are in good agreement with relative dips from other sources such an image analysis.\u0000 The tool deployed successfully and enabled optimum reservoir exposure in a good porosity zone. Along the boundary orientation for geosteering purposes, the technology was able to map another two porous zones within a 20 ft depth of the investigation. The qualitative formation resistivity, both Rh and Rv, were also used for formation evaluation in this reservoir at the well location, which brought the robust information value, especially in high angle and horizontal (HA/HZ) wells because of the complicated tool responses when crossing boundaries. Deep directional EM tools are beneficial for inversions to derive formation properties since they provide more measurements and information about the formation resistivity without the need to cross layer boundaries. Data validation done through several validations by comparing the RhRv value with the vertical well resistivity. Other than that, we also did a general approach for solving formation parameters to search through all possible model scenario and find the one that best matches the actual 2 Mhz 28 and 16-in. coaxial propagation responses using a 2-layer model.\u0000 Initial run results are very encouraging, demonstrating the value to improve efficiency in reservoir characterization and interpretation. The technology enables better understanding the reservoir architecture and formation evaluation through several application from single LWD measurement.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115495701","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":"Evaluating Complex Lacustrine Carbonate Reservoir by Integrating Advanced Logging Techniques and Core Measurements-A Case Study in Qiadam Basin","authors":"Wen An Chen, D. Yu, Guoyan Liu, Qing Bo Li, Diqiu Zhang, Meng Zhao, Fang fang Wu, Liang Cai, Xianran Zhao, Shenzhuan Li, J. Wu","doi":"10.2118/212607-ms","DOIUrl":"https://doi.org/10.2118/212607-ms","url":null,"abstract":"\u0000 A complex and tight lacustrine carbonate reservoir is the main target reservoir in Qaidam Basin. The diagenesis of shallow-shore lake deposition has created a highly heterogeneous reservoir in both vertical and horizontal directions in terms of lithologies, pore structures, and permeability. The core analysis shows a wide variety of lithologies that include terrigenous clastics (quartz, orthoclase, and plagioclase), carbonate (calcite, dolomite, and ankerite), and evaporite minerals such as anhydrite, etc. Electron microscope analysis shows mainly intercrystallite pores with dolomite, dissolved pores, and microfractures. Associated with the complex lithology and pore structure, reservoir permeability is varied and is mostly less than 0.02mD. Evaluating and characterizing this complex reservoir to find a better pay zone was the objective of this study.\u0000 To evaluate the lithologies, pore structures, porosities, and permeability in quantities accurately, the advanced gamma-ray spectroscopy logs, nuclear magnetic resonance (NMR) logs, and high-resolution micro-resistivity borehole image logs were acquired in some key wells. Integrated with core data such as X-ray diffraction (XRD), mercury injection capillary (MICP), the lithofacies, texture facies, and pore facies were classified based on the minerals from gamma-ray spectroscopy, the textures from borehole image, and the pore sizes from NMR. The combination of these three facies represents the reservoir quality.\u0000 In the study area, the lithofacies were classified into four types, which are high carbonate content facies, middle carbonate content facies, high clay content facies, and high clastic content facies. The texture facies were classified into four types, which are massive texture, layered texture, dissolved texture, and algal texture. The pore structure facies were classified into four types, which are macro facies, meso facies, meso-micro facies, and microfacies. The better pay zone is the combination of high carbonate content facies, algal texture, and macro facies. The pay zone of the reservoir was well defined and mapped with the combination facies vertically and horizontally in the whole study area.\u0000 The integrated solution described in this study leverages the advantages of advanced gamma-ray spectroscopy, NMR, borehole images, and core measurements. It develops a comprehensive understanding of the complex carbonate reservoir and provides the solution to pinpoint the sweet spots and place the horizontal well.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132741516","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":"Field Development Optimization with Stochastic Gradient Method: Application to a Multi-Reservoir Carbonate Field in the Middle East","authors":"E. Barros, S. Szklarz, N. Khoshnevis Gargar, J. Hopman, G. Zirotti, G. Bascialla, T. Ramsay, R. Fonseca","doi":"10.2118/212620-ms","DOIUrl":"https://doi.org/10.2118/212620-ms","url":null,"abstract":"\u0000 Field development planning activities involve decisions that entail multi-billion-dollar investments. Making right design choices is crucial to the techno-economic success of the project. In this paper we demonstrate how state-of-the-art numerical model-based optimization techniques can support asset teams in this complex decision-making process.\u0000 Optimization of real-life field development cases can be computationally very demanding due to the cost of running large amounts of large-scale reservoir simulations, the large number of variables to be optimized and the necessity of accounting for uncertainties, among other reasons. In this work we employ TNO’s EVEReST optimization technology leveraging the StoSAG stochastic gradient-based method to achieve optimized solutions in computationally efficient manner. Besides its computational attractiveness, the StoSAG method also renders the optimization framework flexible to be customized to any specific optimization problem, e.g., optimization of any type of field development decisions, coupling to any industry-standard reservoir simulators and handling any type of objective and constraint functions.\u0000 The optimization framework has been used to optimize the expansion of the development plan of a large field in the Middle East, in particular to support decisions concerning the drilling of (up to) 38 new wells and the upgrading of surface facilities to accommodate incremental production. The challenge is posed by the field being comprised of multiple carbonate reservoirs for which multiple types of decisions need to be optimized, often simultaneously i.e. well target locations, trajectory design features, number and type of wells and their distribution across the different reservoirs as well as the drilling sequence. An economic objective function was used with the operational constraints per reservoir accounted for within the framework.\u0000 Optimization found non-trivial optimal solutions resulting in significant improvements in the economic objective. The optimal strategy revealed improved distribution of wells (and types) among the reservoirs, more suitable drilling order and superior well locations and trajectories compared to the initial strategy. Optimization found well locations and trajectories taking into account complex local well interaction in already densely populated reservoirs with wells. The optimized solutions were benchmarked against the development plan designed by the asset team, and the comparison of strategies confirmed the added value of numerical optimization as a tool to expedite the search of improved development strategies. The nature of the employed optimization method allowed optimized solutions to be achieved with a reduced number of reservoir simulations, which was crucial for the success of this study due to the time-consuming reservoir simulations involved. This showcases the computational advantage of the optimization method and highlights EVEReST as an enabler technology ","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132205478","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":"Integrated Workflow With Hydraulic Fracture Propagation and Production Simulation Technology for Multi-Stage Length Optimization in Horizontal Wells","authors":"Xiang Wang, Changyu Yao, Xinchun Zhu, Tao Yang, Chang Chang, Yueli Li, Jiaping Lu, Longjiao Li, Hanbing Xu, Xingning Huang","doi":"10.2118/212694-ms","DOIUrl":"https://doi.org/10.2118/212694-ms","url":null,"abstract":"\u0000 Low-permeability gas reservoirs generally have the lowproduction, production rapid productivity decline, and low-ultimate recovery. Staged fracturing is usually conducted for horizontal wells. Hydraulic fracturing technology isgenerally used to improve fracture conductivity and well productivity. How to accurately characterize and simulate the distribution characteristics of hydraulic fracture network in 3D space is particularly important. The stress interference between hydraulic fractures as the objective mechanical behavior in the process of staged fracturing affects the geometry fracture network and the productivity of the reservoir post-fracturing. The hydraulic fractures simulation in natural fractured reservoirs is complex shapes, mainly because natural fractures affect the propagation path of hydraulic fractures. The theoretical model used to describe the hydraulic fracturing in homogeneous reservoirs cannot accurately show the complexity of the spatial morphology of hydraulic fractures in naturally fractured formations. The operatorurgently needs a mechanical model that can show the stress interference behavior between multiple fractures and the direction of hydraulic fracture propagation, and be used to simulate the spatial form of multiple hydraulic fractures in staged fracturing of horizontal wells and their propagation behavior in naturally fractured formations. Aiming at the impact of natural fractures in the reservoir on the propagation path of hydraulic fractures, this paper established a mechanical model for distinguishing interference behavior of natural fractures and hydraulic fractures. And analyzed the stress field at the tip of the hydraulic fracture and the stress field acting on the natural fracture surface based on the theories related to rock mechanics and fracture mechanics. On the basis of coupling the 3D geomechanical model and the 3D Discrete Fracture Network (DFN) model, this paper established the discriminant model for hydraulic fractures penetrating natural fractures in 3D space to conduct hydraulic fracture propagation simulation for the horizontal well. The research results can be used to optimize the hydraulic fracturing treatment design,and provide technical support for the effective production and profitable development of low-permeability reservoir resources.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133962680","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":"Evaluation of Different Numerical Techniques for Accurate Modelling of Tracer Flow in Porous Media","authors":"Muhammad Yaralidarani, S. Aghabozorgi, S. A. Farzaneh, M. Sohrabi","doi":"10.2118/212598-ms","DOIUrl":"https://doi.org/10.2118/212598-ms","url":null,"abstract":"Inter-well tracer tests have numerous applications in determining the volumetric sweep, levels of heterogeneity, and delineation of flow barriers such as the faults in subsurface in reservoirs. Tracer tests are also performed in the laboratory to determine core samples’ heterogeneity. Simulation of physical dispersion requires refined models, which inevitably increase the numerical dispersion in the obtained results. In this paper, we quantify the numerical dispersion associated with various techniques available for the simulation of tracer flow. Numerical dispersion in the simulations can be quantified by comparing the simulation results with the experimental data. For this purpose, we first reviewed the fundamentals of tracer flow and introduced the Convection-dispersion equation as a basic model to describe tracer flow in porous media. Then we constructed a refined model to simulate a series of tracer flood scenarios. A detailed sensitivity analysis was carried out in a systematic manner to specify the individual impact of physical and numerical dispersion. Finally, we modelled tracer experiments performed on Indiana Limestone (IL) carbonate rocks to examine the accuracy of Fick's and Darcy's equations, and the results are presented. The impact of both numerical (non-physical) and physical dispersion was examined during the core scale simulations. It was concluded that the numerical TVD algorithm (embedded within the commercial ECLIPSE software) can appropriately model the tracer flow in porous media with minimal numerical errors during simulations. It was also shown that physical dispersion significantly affects tracer test results and that it must be considered when simulating tracer flows by defining an appropriate Peclet number. Finally, the results showed that solving the conventional convection-dispersion equation along with the numerical TVD algorithm can perfectly match the experimental data of several tracer flood tests performed on outcrop Indiana limestone core samples.","PeriodicalId":215106,"journal":{"name":"Day 2 Wed, January 25, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-01-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130017710","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}