Day 1 Mon, November 15, 2021最新文献

{"title":"Extending ESP Run Life By Reducing Shutdowns and Improving Restarts Using Novel Pump Protection Technology","authors":"S. Duran, Mike Plooy, A. Dikshit, Amrendra Kumar, Ehab Abo Deeb, G. Chochua, Sudhakar D. Khade, Abhinandan Tripathi, Jose Trevino, Wesley Atkinson","doi":"10.2118/207926-ms","DOIUrl":"https://doi.org/10.2118/207926-ms","url":null,"abstract":"\u0000 Meeting the production demand in today's market without sacrificing performance of the artificial lift method is critical. Aggressive flowback procedures lead to solids production and unplanned electric submersible pump (ESP) shutdowns because of solids overload. A novel pump protection system has been designed, tested, and installed in the field. The system enhances the ESP life, improves restarts, and reduces downhole vibrations and unplanned shutdown by controlling the solids flowback and sending solids-buildup pressure signals. A comparative study on three ESP wells in the Delaware basin (US) demonstrated the efficacy of the system.\u0000 The system comprises of an intake sand control screen and valve assembly. The novel stainless steel wool screen acts as a three dimensional (3D) filter capable of filtering out particles of 15 to 600 μm, and the valve assembly activated by differential pressure across the screen creates a secondary flow path to allow cyclic cleanup of the screen. Stainless steel wool screen with variable pore sizes is used as the sand control media for its high efficiency in preventing the flow of most of the solid particles. When the solids build up on the screen surface, the valve assembly opens upon reaching a preset differential pressure to enable flow past the screens and into the ESP and allows sands deposited on the screen surface to fall off. The pump protection assembly was tested at surface and installed in three wells along with downhole ESP gauges measuring pressure, temperature and vibrations after pulling out existing ESP completions.\u0000 Qualification testing confirmed the opening of the valve assembly after solids buildup on the stainless steel wool screen. It also validated that the deposited sand fell-off from the screen surface after flow diverted through the valve assembly and pressure differential across screen dropped. In the field installations, the run life of the ESPs improved by an average of 35%, with comparable production volumes and slow drawdowns. In addition, the number of ESP shutdowns related to sand and solids was reduced by as much as 75%, improving longevity of electrical components. The success rate of ESP startups after planned and unplanned shutdowns also improved by 22%. The increase in inlet pressure captured via the downhole gauges when the valve assembly opened indicated the sand control prevention and mitigation system was bridged, and ESP replacement should be scheduled to minimize deferred production from a solids-induced ESP failure and to minimize surface solids management costs. The vibration signal data obtained from downhole sensors confirmed the reliability of the system. Overall, results demonstrate that the system designed is successful at increasing ESP run life without detriment to well production performance.\u0000 The new, field-proven pump protection system along with its components and the completion design substantially increase life of ESP by reducing the number of shutdowns","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76251785","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":"Novel Data-Driven Methodology for Production Allocation Calculation Utilizing Physics-Based Models Coupled and Integrated Within a Digital Framework","authors":"A. Alsaeedi, M. Elabrashy, M. Alzeyoudi, M. Albadi, Sandeep Soni, Jose Isambertt, Deepak Tripathi","doi":"10.2118/207469-ms","DOIUrl":"https://doi.org/10.2118/207469-ms","url":null,"abstract":"\u0000 Determining the production from each well is crucial for financial and technical purposes. Moreover, this production can be anticipated using several different techniques. This paper describes the procedures to calculate the production allocated to each well in a giant gas-producing field by utilizing physics-based models that are orchestrated in a dynamic digital platform to provide a robust and efficient solution.\u0000 The cases for this study of allocating gas rates to individual wells were performed using a digital platform as the primary tool utilized to account for the main productional location factors such as well tests and events that are used to estimate actual production volumes. Subsequently, relevant data is extracted, filtered, and loaded into the system in a dynamic interaction with fewer human interventions. The methodology for calculating the production allocated followed these main steps: a) Determine production per well under existing possible measures, b) Determine well contribution factors, c) Distribute actual rates and production according to allocation factors.\u0000 By using polynomial equations where the inflow performance of the gas wells was verified, the allocation rates were calculated at every desired point of the network. Having an integrated platform proved to be advantageous since it provided a seamless link between different relevant manual and real-time databases and well / network models bringing unique capabilities and benefits. While comparing this integrated and holistic approach versus the previously established one, it was highlighted that production allocation using mainly choke sizes and well test as a sole source for well production can bring significant variations. This creates production mismatches at the well level; therefore, it portrays a misrepresentation of the actual field conditions. Numerous challenges, which are usually faced while calculating the production allocation process, were overcome during the development of this study, such as frequent surface network changes, lack of databases communication, and daily variations on the on/off wells’ status. Furthermore, the data management capabilities of the framework allowed data to be quickly accessible by the users whenever needed allowing them to visualize across the different teams and departments, taking actions when and where required.\u0000 This standardized methodology provided consistency, reliability, and accuracy, which can be replicated on oil-producing fields and networks; it can be enhanced and scaled in order to incorporate other business processes such as well allowable calculation and voidage monitoring.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"232 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73691250","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":"Surge Mapping of Compressors to Enhance Energy Efficiency and Integrity","authors":"Sevideen Abdul Shathar, B. Ramakrishnan, Shafiulla Abdul Jabbar, Reem Al Mansoori","doi":"10.2118/207216-ms","DOIUrl":"https://doi.org/10.2118/207216-ms","url":null,"abstract":"\u0000 ADNOC Gas Processing Ruwais NGL Plant carried out a field surge testing of one of its Centrifugal type Refrigeration compressor units in order to accurately evaluate the real surge points. Centrifugal compressors used in Gas processing plants are critical machineries consuming significant amount of energy. Unavailability of the compressor due to any failure will cause revenue loss and downtime to the plant operators. Often failure of the compressor system happens due to unstable operation caused by surge. Manufacturers build surge control systems to protect the machinery during the project stages through simulation.\u0000 However, inaccurate surge map or shifting of surge control lines during plant operation may result in energy losses or machinery damage. Surge test establishes the baseline for machine to help understand future issues better, for machinery protection, safe operation and efficiency.\u0000 Performing high risk surge testing activity in a safe and successful manner during plant operation and re-mapping resulted in optimal utilization of existing assets without the need for costly upgrades.\u0000 This innovative technique can lead to impressive improvements and benefits on equipment integrity, performance, energy efficiency, emissions and profitability. This best practice has great potential for transferability across Oil & Gas industry as such compressors and control systems are common across the industry.\u0000 This paper highlights the methodology of accurate mapping of surge control lines in a safe manner during plant operation to enhance energy efficiency of the machine by reduced gas recycles and to enhance machine integrity by avoiding early surge possibilities.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"266 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75778192","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":"Produced Water Reuse for Drilling and Completion Fluids Using Ion Exchange Resins","authors":"Hind S. Dossary, Fahd I. Alghunaimi, Young-Chan Choi","doi":"10.2118/207543-ms","DOIUrl":"https://doi.org/10.2118/207543-ms","url":null,"abstract":"\u0000 Produced water is considered one of the largest by volume waste streams and one of the most challenging effluents in the oil and gas industry. This is due to the variety of contaminants that make up produce water. A variety of treatment methods have been studied and implemented. These methods aim to reduce the hydrocarbon content and the number of contaminants in produced water to meet the disposal, reuse, and environmental regulations. These contaminants can include dispersed oil droplets, suspended solids, dissolved solids, heavy metals, and other production chemicals. Some of those contaminates have value and can be a commodity in different applications such as bromine (Br). Bromine ions can be used to form calcium bromide, which is considered one of the most effective drilling agents and is used extensively in drilling and completion operations. This paper aims to highlight the utilization and the new extraction method of bromide ions from produced water to form calcium bromide (CaBr2). The conventional preparation of calcium-bromide drilling and completion fluids involves adding solid calcium-bromide salts to the water, which can be relatively expensive. Another method can involve the handling of strong oxidants and toxic gas to form solid calcium bromide. The novel method outlined in this paper is a cost-effective and environmentally friendly way of generating calcium bromide from produced water. The method includes processing the produced water to recover bromide ions. This is done by first passing the produced water through a resin bed, including bromine-specific ion exchange resin, where the bromide ions will adsorb/absorb onto the resin, as shown in Figure-1. The second step involves regenerating the resin with regenerant having calcium cations and water to form calcium bromide. The final stage is generating the calcium bromide in the water from the bed of resin by introducing concentrated CaCl2, forming a concentrated solution of water and calcium bromide. The developed solution will be further processed to give drilling and completion fluids. This novel method constitutes a good example of produced water utilization in different applications to minimize waste and reduce the costs of forming highly consumable materials.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72791161","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":"User Generated Content for Site Based Training in Virtual Reality","authors":"Ivory Mayhorn, Kyle R. Daughtry, Athicha Dhanormchitphong, Mitchell B. Bray","doi":"10.2118/207299-ms","DOIUrl":"https://doi.org/10.2118/207299-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Through a partnership with Global Projects and the ExxonMobil IT, we set out to change the way enabling enhanced site specific operator training and model reviews are done on large complex models. The concept was to have the ability to view and navigate complex green-field 3D CAD models in VR (virtual reality) technology to aid in training, model reviews, procedure development, rounds development, maintenance planning and execution, emergency response planning / drills, and project planning. The automated toolset can be used to conduct model reviews followed by training and preparing operators for commissioning before and after site construction is completed.\u0000 \u0000 \u0000 \u0000 Leveraging the 3D CAD files from Engineering Procurement & Construction (EPC) contractors, the feature set allows the ability to create a fully textured 3D Model walk-through (annotated model review), and a content creation application to easily create user generated training scenarios (similar to PowerPoint drag and drop). In the past few months, 20 onsite stations were setup and over 100 first and second line supervisors and operators leveraged the toolset. Baseline metrics were captured with an overwhelming success. Ongoing metrics collections will continue for several months to drive further adjustments on the toolset to ensure high value capture. This toolset, once fully refined, will allow other capital & global projects the ability to train operators prior to the unit being built and ongoing for operations activities bringing pieces of the Digital Twin concept to life.\u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000 \u0000","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78218203","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 Real-Time Geomechanical Modeling to Prevent Wellbore Instability While Drilling Horizontal Wells with Extended Reservoir Contact","authors":"E. Gomez, Raider Rivas, E. Ombe, Sajjad Ahmed","doi":"10.2118/207985-ms","DOIUrl":"https://doi.org/10.2118/207985-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Drilling deviated and horizontal high-pressure, high-temperature (HPHT) wells is associated with unique drilling challenges, especially when formation heterogeneity, variation in formation thickness as well as formation structural complexities are encountered while drilling. One of the major challenges encountered is the difficulty of landing horizontal lateral within the thin reservoir layers. Geomechanical modeling has proven to be a vital tool in optimizing casing setting depths and significantly increasing the possible lateral length within hydrocarbon bearing reservoirs. This approach ultimately enhanced the production output of the wells.\u0000 In a particular field, the horizontal wells are constructed by first drilling 8 3/8\" hole section to land about 5 to 10’ into the impervious cap rock just above the target reservoir. The 7\" casing is then run and cemented in place, after which the horizontal hole section, usually a 5 7/8\" lateral, is drilled by geosteered within the target reservoir to access its best porosity and permeability. Due to the uncertainty of the cap rock thickness, setting the 7\" liner at this depth was necessary to avoid drilling too deep into the cap rock and penetrating the target reservoir. This approach has its disadvantages, especially while drilling the 5-7/8\" lateral. Numerous drilling challenges were encountered while drilling the horizontal lateral across the hard cap rock. like severe wellbore instability, low ROP and severe drillstring vibration.\u0000 To mitigate the challenges mentioned above, geomechanical modelling was introduced into the well planning process to optimize the 8 3/8\" hole landing depth within the cap rock, thereby reducing the hard caprock interval to be drilled in the next section. Firstly, actual formation properties and in-situ rock stress data were obtained from logs taken in previously drilled wells in the field. This information was then fed into in the geomechanical models to produce near accurate rock properties and stresses values. Data from the formation fracture strength database was also used to calibrate the resulting horizontal stresses and formation breakdown pressure. In addition to this, the formation pore pressure variability was established with the measured formation pressure data. The porosity development information was also used to determine the best landing depths to isolate and case-off the nonreservoir formations. Combined with in-depth well placement studies to determine the optimal well trajectory and wellbore landing strategy, geomechanical modelling enabled the deepening of the 8 3/8\" landing depth without penetrating the hydrocarbon reservoir. The geomechanical models were also updated with actual well data in real time and allowed for the optimization of mud weight on the fly. This strategy minimized near wellbore damage across the reservoir section and ultimately improved the wells productivity index.\u0000 Deepening of the 8 3/8\" landing depth and minimizing the foo","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78112181","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":"Prediction of Threshold Sand Rates from Acoustic Monitors Using Artificial Intelligence","authors":"Ronald E. Vieira, Bohan Xu, Asad Nadeem, Ahmed Nadeem, S. Shirazi","doi":"10.2118/208162-ms","DOIUrl":"https://doi.org/10.2118/208162-ms","url":null,"abstract":"\u0000 Solids production from oil and gas wells can cause excessive damage resulting in safety hazards and expensive repairs. To prevent the problems associated with sand influx, ultrasonic devices can be used to provide a warning when sand is being produced in pipelines. One of the most used methods for sand detection is utilizing commercially available acoustic sand monitors that clamp to the outside of pipe wall and measures the acoustic energy generated by sand grain impacts on the inner side of a pipe wall. Although the transducer used by acoustic monitors is especially sensitive to acoustic emissions due to particle impact, it also reacts to flow induced noise as well (background noise). The acoustic monitor output does not exceed the background noise level until a sufficient sand rate is entrained in the flow that causes a signal output that is higher than the background noise level. This sand rate is referred to as the threshold sand rate or TSR. A significant amount of data has been compiled over the years for TSR at the Tulsa University Sand Management Projects (TUSMP) for various flow conditions with stainless steel pipe material. However, to use this data to develop a model for different flow patterns, fluid properties, pipe, and sand sizes is challenging. The purpose of this work is to develop an artificial intelligence (AI) methodology using machine learning (ML) models to determine TSR for a broad range of operating conditions.\u0000 More than 250 cases from previous literature as well as ongoing research have been used to train and test the ML models. The data utilized in this work has been generated mostly in a large-scale multiphase flow loop for sand sizes ranging from 25 to 300 μm varying sand concentrations and pipe diameters from 25.4 mm to 101.6 mm ID in vertical and horizontal directions downstream of elbows. The ML algorithms including elastic net, random forest, support vector machine and gradient boosting, are optimized using nested cross-validation and the model performance is evaluated by R-squared score.\u0000 The machine learning models were used to predict TSR for various velocity combinations under different flow patterns with sand. The sensitivity to changes of input parameters on predicted TSR was also investigated. The method for TSR prediction based on ML algorithms trained on lab data is also validated on actual field conditions available in the literature. The AI method results reveal a good training performance and prediction for a variety of flow conditions and pipe sizes not tested before.\u0000 This work provides a framework describing a novel methodology with an expanded database to utilize Artificial Intelligence to correlate the TSR with the most common production input parameters.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91110151","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":"Systematic Modelling of Unstable Displacement","authors":"A. Skauge, K. Sorbie, I. C. Salmo, T. Skauge","doi":"10.2118/207493-ms","DOIUrl":"https://doi.org/10.2118/207493-ms","url":null,"abstract":"\u0000 Modelling unstable displacement is a challenge which may lead to large errors in reservoir simulations. Field scale coarse grid simulations therefore need to be anchored to more reliable fine grid models which capture fluid displacement instabilities in a physically correct manner. In this paper, a recently developed approach for accurately modelling viscous fingering has been applied to various types of unstable displacement.\u0000 The method involves estimation of dispersivity of the porous medium and length scale of the model to determine the required size of the simulation grid cell. Fractional flow theory is then applied to obtain the correct saturation of the injected phase in the unstable fingers formed due to the adverse mobility ratio. Unstable displacement experiments have been history matched using 2D-imaging of in-situ saturation as a calibration of our method, before carrying out sensitivity calculations on the effect of fluid viscosity, and rock heterogeneity. Our modelling approach allows us to carry out simulations using a conventional numerical simulator using elementary numerical methods (e.g. single-point upstreaming).\u0000 The methods used to model instability (Sorbie et al, 2020) was originally developed for immiscible water/oil systems. The current paper now presents new results applying this approach to unstable gas displacements, where adverse viscosity ratios may be even higher than in water/oil systems. The displacement with injected gas is shown to be influenced by mass exchanges between the gas and oil as the alternating fluids (water and gas) are injected in WAG processes. Swelling of fingers delay the gas front and WAG processes divert the injected gas and improve sweep efficiency. We have also modelled water-oil displacement at adverse mobility and shown the benefit which is obtained by reducing the instability by adding polymers to viscosify the injected water. The impact of rock heterogeneity has different effect depending on buoyancy forces and the degree of crossflow into the high permeable zones.\u0000 This paper extends our novel approach to modelling the fine scale distribution of the injected fluids in adverse mobility ratio displacements. This approach has now been applied to both, gas/oil and water/oil systems where viscous fingering is present, either at extremely adverse mobility ratios and/or for reservoirs where the permeability field is very heterogeneous.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"108 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89943743","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":"The Intelligent Field Development Plan Through Integrated Cloud Computing and Artificial Intelligence AI Solutions","authors":"Samat Ramatullayev, Shi Su, Coriolan Rat, Alaa Maarouf, Monica Mihai, Hussein Mustapha, Yanfidra Djanuar, Qingfeng Huang, Lamia Rouis","doi":"10.2118/208106-ms","DOIUrl":"https://doi.org/10.2118/208106-ms","url":null,"abstract":"\u0000 Brownfield field development plans (FDP) must be revisited on a regular basis to ensure the generation of production enhancement opportunities and to unlock challenging untapped reserves. However, for decades, the conventional workflows have remained largely unchanged, inefficient, and time-consuming. The aim of this paper is to demonstrate that combination of the cutting-edge cloud computing technology along with artificial intelligence (AI) and machine learning (ML) solutions enable an optimization plan to be delivered in weeks rather than months with higher confidence.\u0000 During this FDP optimization process, every stage necessitates the use of smart components (AI & ML techniques) starting from reservoir/production data analytics to history match and forecast.\u0000 A combined cloud computing and AI solutions are introduced. First, several static and dynamic uncertainty parameters are identified, which are inherited from static modelling and the history match. Second, the elastic cloud computing technology is harnessed to perform hundreds to thousands of history match scenarios with the uncertainty parameters in a much shorter period. Then AI techniques are applied to extract the dominant key features and determine the most likely values. During the FDP optimization process, the data liberation paved the way for intelligent well placement which identifies the \"sweet spots\" using a probabilistic approach, facilitating the identification and quantification of by-passed oil.\u0000 The use of AI-assisted analytics revealed how the gas-oil ratio behavior of various wells drilled at various locations in the field changed over time. It also explained why this behavior was observed in one region of the reservoir when another nearby reservoir was not suffering from the same phenomenon. The cloud computing technology allowed to screen hundreds of uncertainty cases using high-resolution reservoir simulator within an hour. The results of the screening runs were fed into an AI optimizer, which produced the best possible combination of uncertainty parameters, resulting in an ensemble of history-matched cases with the lowest mismatch objective functions. We used an intuitive history matching analysis solution that can visualize mismatch quality of all wells of various parameters in an automated manner to determine the history matching quality of an ensemble of cases. Finally, the cloud ecosystem's data liberation capability enabled the implementation of an intelligent algorithm for the identification of new infill wells.\u0000 The approach serves as a benchmark for optimizing FDP of any reservoir by orders of magnitude faster compared to conventional workflows.\u0000 The methodology is unique in that it uses cloud computing technology and cutting-edge AI methods to create an integrated intelligent framework for FDP that generates rapid insights and reliable results, accelerates decision making, and speeds up the entire process by orders of magnitude.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"124 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87823803","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":"Coiled Tubing Workflow Leads to Successful Completion of Multistage Fracturing in Extended-Reach Wells of Aishwarya Field, Barmer, India","authors":"F. Jahn, Madhurjya Dehingia, Ishaan Singh, Bholanath Bandyopadhyay, Arpit Agarwal, Atul Singh","doi":"10.2118/208004-ms","DOIUrl":"https://doi.org/10.2118/208004-ms","url":null,"abstract":"\u0000 Coiled tubing (CT) was used to perform multistage fracturing treatments from the CT-tubing annulus in extended-reach wells of Aishwarya Field, Barmer, India. The wells were completed with chrome completion and included multiple fracturing sleeves. With peculiar challenges faced, solutions and lessons learnt are herein captured. In particular, casing deformation was observed in transverse wells, for which the workflow was developed so the wells with post-fracturing casing deformation could be completed and delivered for production.\u0000 During the initial phase of the campaign. CT got stuck eight times after fracturing due to casing deformation. In three instances, the bottomhole assembly was left in the hole, and twice the CT was cut for recovery. After the workflow was implemented, no CT stuck incidents occurred due to casing deformation, and all 16 transverse wells in the campaign were delivered successfully.\u0000 This study highlights the importance of differentiating between transverse and longitudinal wells while understanding their implications. In wells where casing deformation can occur, the workflow for CT-assisted multistage fracturing (MSF) operations must be adjusted. A smaller outside diameter (OD) shifting tool needs to be used without a packer assembly, and the CT cannot stay in the well during fracturing.","PeriodicalId":10967,"journal":{"name":"Day 1 Mon, November 15, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86588408","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}