Day 1 Wed, March 01, 2023最新文献

{"title":"Brilliant at the Basics: A Review on Dual String Gas Lift Injection Performance in Malaysian Offshore Fields","authors":"Alister Albert Suggust, Jing Zhi Kueh","doi":"10.2523/iptc-22806-ms","DOIUrl":"https://doi.org/10.2523/iptc-22806-ms","url":null,"abstract":"\u0000 Sarawak offshore wells are mostly completed with dual string completion and are heavily relying on gas lift as the primary artificial lift. Dual string gas lift is an economical way to selectively produce from multi-stacked reservoirs in Sarawak fields. However, it poses great challenges in terms of operations, troubleshooting, allocation and optimization as both strings share a common annulus. Dual string gas lift performance diagnosis need to be done from time to time to ensure the strings production are optimized at well level.\u0000 Gas injection rate is a critical input in predicting the well performance based on the gas lift performance curve. However, the gas lift injection rate for dual string is measured at well – not at string level. The gas lift injection rate into each string needs to be allocated correctly either through well modelling calibration approach, testing one string while shutting its neighbor or well tracer application. After allocating the gas lift injection rate into each string correctly, well modelling prediction run at done to mitigate multipointing issues, design optimum point of injection, establish optimum injection rate at well level and determine the optimum casing head pressure.\u0000 The operator has proposed for a workflow to correct the dual gas lift injection allocation based on well modelling calibration. The workflow was implemented and resulted in multiple optimizations in terms of gas lift valve change program, choke optimization and gas lift rate optimization. Apart from that, the paper will also share on the findings from the well tracer application in correcting the gas injection allocation.\u0000 This paper will focus on the production performance check on dual string gas lift performance at well level. The findings from the study are subsequently monetized as quick-gain opportunities while the operator is embarking into long term study on assessing the alternative artificial lift strategy suitable for a brownfield. The lessons learned will also be applicable to oil fields with similar situations to further improve the fields’ production.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123360642","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":"Innovative Way of Improving S1 Production and Operation Using Real-Time Flowline Simulations of S1 Flowline Networks","authors":"Boonyakorn Assavanives, Saranee Nitayaphan, Kantkanit Watanakun, Choosak Kokanutranont, Prakitr Srisuma, Sumbhat Wanwilairat, Pimpisa Pechvijitra, Tattanan Permpholtantana, Worawat Rungfarmai, Naruedon Thatan","doi":"10.2523/iptc-22800-ea","DOIUrl":"https://doi.org/10.2523/iptc-22800-ea","url":null,"abstract":"\u0000 It is always a challenge of legacy oil field to optimize the production with complex flowline network. Greater Sirikit (S1) oil field is operating with 400 wells, approximately, from 800 wells and over 100 flowlines. Therefore, flowline route adjustment is a crucial assignment to minimize pressure at wellheads for maximum production. Currently, the flowline simulations are used to model S1 flowline network, including crude production flowlines, gas lift flowlines, and water injection flowlines to check pressure drop and flowline size. All flowline management activities have been performed manually through numerous trial and errors and hand calculations to maintain production target. However, such method is time-consuming, and the results are not yet optimized.\u0000 A new innovative workflow is developed from the current flowline simulation models combined with online real-time data by Python programming. This innovative module imports data from the Production Data Management System (PDMS) to flowline simulation models and computes automatically through loops and conditioning algorithms commanded by Python toolkit. Methodology of an innovative module is to optimize production based on operating pressure from the wellheads to Flow Station (F/STN). The wellhead flowrate can be initially predicted from the well testing data while the operating conditions are from online data. The created module prioritizes the parameters that are bottlenecks for maximum production, e.g., high back pressure flowlines, or high water cut wells. Then, the module can selectively operate the wells and adjust the flowline routes with hill climbing optimization technique and conditioning algorithms to obtain the best operating scenario where the maximum production rate is achieved. Without human interference, an integration of an innovative module and flowline simulation models creates the seamless interoperability between BigQuery database and the simulation software. The accuracy and precision verification are a crucial process before module endorsement. Debugging and re-verification are repeated to ensure the validaty of the module. It is foreseen that the prospective pressure reduction will be at 10%, which potentially enhances more production. Economic evaluation has been carried out at expected production rate of S1 field. Flow line pressure management and allocation by program can reduce back pressure by 10 psi which increases production rate of 3840 Bbl/d from 400 active wells. The new work process also helps to reduce Full-time equivalent (FTE) and accelerates cycle time which makes work process agile, able to check anytime. The application intends to implement at S1 asset but not limited to. With the power and flexibility of Python ecosystem, it enables multistep workflows that can be shared, and the configuration can be extended to other assets or other operating oil and gas fields.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127932615","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":"Long-Term Productivity Monitoring of Multistage Wells with New Quantum Dot Technology and its Application in Xinjiang Oilfield","authors":"Yan Junhong, Pang Pei, Li Zhongbao, _. Sunxin, Tian Zhihua, Qiu Ziyao, Wang Guangyu, A. Belova","doi":"10.2523/iptc-23030-ea","DOIUrl":"https://doi.org/10.2523/iptc-23030-ea","url":null,"abstract":"\u0000 Traditional production logging uses cable or coiled tubing for productivity measurement. Such measurement normally requires well to be shut-in, which brings risks for field operation, especially for directional or horizontal wells; it affects normal field production management. Besides, the result only reflects production profile at one time point. The later production system adjustment or changes of water production value need to be measured again, eventually increasing the total cost.\u0000 Productivity monitoring technology based on ‘Quantum Dot’ tracers uses nano-size quantum dots to make micron-size quantum signature codes or marker-reporters. As the basic monitoring particle, the quantum signature code can be made to flake quantum dot monitoring tape through polymer materials, this special tape is wrapped around pipe or screen and placed at target location in the borehole. For different layers and fluid phases, quantum monitoring tapes with different codes and affinity properties are utilized to distinguish them. When monitoring tapes come into contact with different fluids such as oil or water in formation, diffusion channels will be generated, from which quantum monitoring particles (marker-reporters) are released and adsorbed on the surface of the material. As fluid flows, quantum monitoring particles in monitoring tapes will be continually released and adsorbed on tapes surface and carried to the wellbore, this achieves a release process proportional to flow rate. The produced liquid collected at wellhead is mixed with quantum monitoring particles with various codes, which can be separated by laboratory analysis. By counting the percentage of marker-reporters with different codes, the production rate percentage of different intervals can be obtained, and then for each stage, oil, gas, and water production can be obtained according to the total wellhead production. The quantity of quantum monitoring particles is massive, and its release rate is in a positive correlation to flow rate. Under normal circumstances, unlimited production monitoring can be achieved within 3 years.\u0000 Traditional production logging measure formation and production parameters such as temperature, pressure, density, resistivity, flow rate, water cut etc. logging tools and packers are combined to measure flow volume from each stage and fluid types are identified at wellhead.\u0000 Main disadvantage of this method is the requirement for wellbore shut-in and the risk of unsuccessful RIH the tools as the wellbore faces common issue – wellbore deformation.\u0000 In addition, it is not normal using packers to isolate other zones while allowing only one stage to produce. Also, production logging can only obtain inflow profile at a specific time or short period of time. If one needs to get information such as later production data or water cut value when producing system is adjusted or changed, logging operation must be done again. It results in higher costs.\u0000 How to monitor production ","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"259 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116246867","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 Simulation Software to Enhance Filter Cake Breaker Placement","authors":"Kesavan Govinathan, Samyak Jain, Anandhadhasan Balasandran, Kim Teng Yeo","doi":"10.2523/iptc-22756-ms","DOIUrl":"https://doi.org/10.2523/iptc-22756-ms","url":null,"abstract":"\u0000 Placement of a delayed filter cake breaker fluid system is usually carried out during the lower completion phase of a well development. Whilst the fluid system would undergo extensive testing during its design phase, the objective of achieving a good clean-up of the target interval requires both testing and an optimum placement strategy. A good clean-up improves the possibility of achieving the desired production rates when the well is put on production.\u0000 Placement of the treatment should always be performed below the fracture pressure. If that limit is breached during pumping of the treatment, it can induce losses which would likely result in poor and non-uniform breaker placement and potentially a well control issue. Detailed pre job design and planning using a sand control simulation software allows improved insight and precision to the placement strategy. It also facilitates a better understanding of the completion optimizations that can be incorporated prior to the breaker treatment. This allows the treatment to be kept below fracture pressure and control the losses to the formation.\u0000 The use of the software for this application was found to be very effective to optimize pumping rates and manage dynamic pressure limitations using well and completion data. The simulation software was utilized to evaluate multiple scenarios with variable input parameters and the results were analyzed to provide valuable insight into the impact this has on the pumping pressure and equivalent circulating density (ECD) margins.\u0000 The paper presents examples of how the breaker treatment design strategy was optimized using the simulation software. Comparison of the modelled and actual data is presented to confirm accuracy and demonstrate how the model can be used to further optimize the design for future operations.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131606833","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":"Seismic Driven Machine Learning to Improve Precision and Accelerate Screening Shallow Gas Potentials in Tunu Shallow Gas Zone, Mahakam Delta, Indonesia","authors":"R. Herbet, M. I. Hibatullah, D. Restiadi, Cepi M.Adam, Andrean Satria, T. Rusady, M. Mordekhai, Khairul Ummah","doi":"10.2523/iptc-23075-ms","DOIUrl":"https://doi.org/10.2523/iptc-23075-ms","url":null,"abstract":"\u0000 Tunu Shallow Zone (TSZ) is one of producing zone in Tunu Field. Tunu Field is a giant gas field located in the present-day Mahakam Delta, East Kalimantan, Indonesia. The gas reservoirs are scattered along the Tunu Shallow Zone and correspond with fluvio-deltaic series and main lithologies are shale, sand and coal layes. The development of TSZ heavily relies on seismic to access and identify gas sand reservoirs as drilling targets.\u0000 Anomaly seismic is correspond with the gas sand reservoirs, however with the conventional use of seismic that is difficult for differentiating the gas sands from the coal layers. We established Tunu reliable technology which is comprised four different analyses on stacks, CDP Gathers, AVA/AVO, and litho-seismic cube. We are hit high success rate in identifying gas but requires a lot of time to assess the prospect. But the challenge is to access more than 20, 000 shallow geobodies in time manner, faster and more efficient to fulfill our drilling sequences target and speed-up the development phase.\u0000 Therefore, we are developing seismic driven supervised machine learning to fit learn geological Tunu characteristic to be gas reservoirs. Several machine learning algorithm has been tested and selected based on several criteria such as AVA/AVO, and amplitude of seismic. The algorithm used to learn behavior of seismic correspond with gas reservoir from data training then applied it to validation and blind dataset for evaluating final models. The final machine learning output is gas probability cube with precision of 70-80% precision from well drilled result in term of gas occurence. Furthermore, unsupervised machine learning has been used to extract potential prospecting targets as geobody targets. Initial test showed encouraging result to extract geobody targets in the shorter time compare with the conventional geomodeling. The final goals are optimizing our current workflow for screening shallow gas potentials, accelerate screening in the future well targets with more efficient, effective way and independent of subjectivity, allowing 2G (geologist and geophysicists) explore deeper and confident way when targeting next future shallow gas target.\u0000 Usage of seismic driven machine learning for targeting shallow gas reservoir is one big step in the current oil and gas industry and in the same time opening more opportunity to maximize powerful machine learning in 4.0 industry era which is need accuracy, more precise, robust, faster and efficient.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"14 5","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114030524","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":"A Breakthrough Solution to Set ESP Packer at Higher Inclination by a Creative Combination of Re-Designing Slick-Line Tool String, Completion String and Well Trajectory Saving up to 30% of Completion Time in a Middle East Depleted Oil Field.","authors":"Mustafa Almuallim, S. Ullah, A. Ruzhnikov, Paul Silva, Jaffar Al Shaikh, R. Agarwal, Mohammad Al-Herz","doi":"10.2523/iptc-22757-ea","DOIUrl":"https://doi.org/10.2523/iptc-22757-ea","url":null,"abstract":"\u0000 After years of oil production in the Middle East, conventional electric submersible pump (ESP) placement at inclination of 45° is no longer deep enough to enable inflow of hydrocarbons. As a result, in some fields a packer placement is pushed deeper and closer to a reservoir at 55°-70° inclination which negatively impacts the ability to set packer with conventionally slick-line run plug system. The paper provides information on technologies used to overcome challenges associated by use of creative solution of modified slick-line run tubing plug system aiming to set the production packers at high inclination, in excess of 45°.\u0000 This optimized system eliminates risk of weakened slickline jarring action across deviated wellbore by optimizing landing plug design, completion string configuration and landing profile criteria at which plug is deployed to pressurize tubing and set completion packer. The manuscript discusses torque and drag modeling utilized to plan and monitor deployment of modified slick-line system across high deviated and extended reach (ERD) wells. Finally, paper concludes with a detailed deployment BHA, execution road map and contingencies.\u0000 The abovementioned system was successfully implemented across 5 extended reach wells (ERD) with packer set at an inclination up to 70°. Revised approached enabled optimization of both slick-line BHA and completion string such, that cost is reduced by over 30% compared to other wells where packer was set with conventional approaches like coiled tubing and wireline tractor. Furthermore, time associated with completion operation has been reduced by more than 2 days. Utilized model of slick-line deployment is currently adopted by the operator as standard practice to set ESP packer across highly deviated trajectories for both multi- and single lateral extended reach oil wells.\u0000 The document provides a novel approach to set production packer at high inclination by utilization of optimized deployment BHA comparing to more expensive and time-consuming alternative approaches. It also provides technical feasibility analysis for slickline deployment into wellbores of high inclination. The proposed approach can be implemented any project worldwide to optimize both wireline and slick-line operation and thereby improving the performance.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124147085","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":"Innovative Formation Testing Methods to Enhance the Field Development Plan: a Case Study in South-East Asia","authors":"Akira Nakatani, Anthony Cartwright, J. Copp, T. Khunaworawet, S. Daungkaew, L. Phan, V. Kieu, Jagdeve Babu H.","doi":"10.2523/iptc-23047-ea","DOIUrl":"https://doi.org/10.2523/iptc-23047-ea","url":null,"abstract":"\u0000 In early 2010s, two gas and gas condensate fields were discovered in a South-East Asia Basin. The Field Development Plan (FDP) was approved to develop both. After drilling several wells, the operator encountered complex challenges: (1) lower permeability reservoirs (2) complex HPHT subsurface structures (3) fluid identification, (4) reservoir understanding and connectivity. Formation evaluation, especially formation testers were therefore crucial for better reservoir understanding, to de-risk the FDP and maximize future productivity of the field.\u0000 This paper will discuss formation evaluation and formation testing in this campaign which consists of more than 10 jobs. Firstly, proper pre-job design and planning was done based on reservoir fluid information and reservoir properties from the previous exploration campaign. Analytical and numerical simulation models were conducted to properly design the Formation Tester (FT) tool string: probe/packer types, pump rate, and displacement unit types. Later, logging operation procedure, real time monitoring, and communication protocol will be also discussed with lessons learned and best practices. This workflow has set another milestone for fit-for-purpose solutions to tackle the reservoir and operational challenges.\u0000 In this campaign, apart from a new discovery, based on Downhole Fluid Analyzer (DFA) technology, we surprisingly proved different fluids in the deeper reservoirs. In addition, we were able to address reservoir connectivity, the main uncertainty in their FDP. This paper also discusses several innovative methods associated with FT technology to reduce uncertainties in the FDP such as:\u0000 The FT selection to help obtain best reservoir data, even in the most challenging environments such as low permeability, uncertain reservoir fluids, HPHT, and complex subsurface structure. As no well test was planned, Interval Pressure Transient Test (IPTT) data was used to obtain zone permeability which was later used to calibrate petrophysical data and the dynamic reservoir model. The use of pressure and DFA data to understand reservoir connectivity. The comparison between DFA data and PVT lab results will be also discussed. The use of advanced reservoir simulation software to understand reservoir contact uncertainty and improve reserve estimation.\u0000 From this work, we have learnt that collaboration between different teams and disciplines is most important for this to be a smooth and seamless operation. Innovation and sustainability workflows are always possible to adapt in order to achieve good results even in the most challenging environments.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127223438","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":"Mixed Preformed Particle Gel System for Water Shutoff in Fractured Carbonate Reservoir","authors":"D. Cao, Ayman Almohsin, M. Han, B. Al-Harbi","doi":"10.2523/iptc-23006-ms","DOIUrl":"https://doi.org/10.2523/iptc-23006-ms","url":null,"abstract":"\u0000 Water shutoff from production well using particle type material is a great challenge due to the complex pressure and flow distributions near wellbore. A mixed preformed particle gel (PPG) system was developed to enhance the performance for water shutoff in fractured carbonate reservoirs. The PPG blocking behaviors in fractures and methods to improve the water flush tolerance were investigated. PPG strength dominated the water shutoff performances in fractures. PPG with medium to high strength showed better performance than other samples due to the well-adjusted properties in blocking and flush tolerance. For the selected PPG, 30 mesh sample showed the best blocking performance among single mesh samples from 20 mesh to 80 mesh in the fractured artificial metal plug. Using 30 mesh sample as base sample, the 30 mesh and 40 mesh mixture with weight ratio 2:1 produced highest pressure build-up in two-size PPG mixtures. Further increasing the particle size distribution by combining various particle size PPGs, the blocking performance was improved. An optimized combination of 30 mesh, 40 mesh, 50 mesh and 60 mesh particles with weigh ratio of 4:2:1:0.25 was developed. In addition, a fiber material, added in the PPG, significantly improved the water flush tolerance of the PPG pack. A particle size combination of PPGs mixed with the fiber material generated better blocking performances than the other combinations. This study provides insights on packing behavior of deformable gel particles in fractures with a practical PPG based system for water shutoff treatments.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129312594","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":"Risk Mitigation Strategy Improves Drilling Performance with Geomechanical Modelling in Horizontal Wells","authors":"Tang Li, Jianhai Li, Jixiang Cao, Jinxi Wang, Chen Gong, Yantao Deng","doi":"10.2523/iptc-22855-ms","DOIUrl":"https://doi.org/10.2523/iptc-22855-ms","url":null,"abstract":"\u0000 The problem of wellbore instability is a worldwide technical problem in the field of the drilling engineering and one of the core problems for the safe and efficient drilling. After the drill bit drills the formation and a borehole is formed, the drilling fluid column pressure replaces the support provided by the drilled rock stratum, upsetting the original stress balance of the formation, and causing the stress redistribution of the rock around the borehole. If the redistributed stress exceeds the maximum load that the rock can bear, it will lead to wellbore instability. At the same time, the invasion of the drilling fluid filtrate into the formation will cause an increase in the formation pore pressure and a decrease in rock strength, further aggravating the instability of the wellbore. In tight gas development, the particularity of the drilling of the long-horizontal wells, during which the unstable bedded sandstone is taken as the target layer, the distribution of the secondary stress around horizontal wells, which is very different from that of vertical wells, the complex stress environment of tight gas reservoirs, and the well-developed bedding/fractures all increase the risk of wellbore collapse and instability. Based on the pore elasticity and single structural plane strength theory, this paper establishes a mechanical analysis model for the wellbore stability of horizontal wells in layered shale to analyze the effects of bedding plane occurrence (strike, dip angle), wellbore trajectory (wellbore orientation), and weakening of bedding plane strength on wellbore stability of horizontal wells. Besides, this paper establishes a three-dimensional geomechanical model of Zhongqian 1 block based on the geomechanical modeling technology to precisely characterize the distribution characteristics of mechanical parameters in three-dimensional space to provide technical support for the optimization of horizontal well drilling plan.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"101 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127185728","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 Measurement and Control Technology for Intelligent Artificial Lift Based on Multiphase Flowmeter","authors":"Guanhong Chen, Feng Deng, Shiwen Chen, Junfeng Shi, Weidong Jiang, Gaoqiang Ma, Cai Wang","doi":"10.2523/iptc-23051-ea","DOIUrl":"https://doi.org/10.2523/iptc-23051-ea","url":null,"abstract":"\u0000 Intermittent oil recovery is a direct and effective way to reduce energy consumption and improve recovery efficiency. However, the existing open and shut-in well procedure relies on manual control, which has problems such as increased labor costs, changeless intermittent parameters, poor energy saving, and also brings hidden dangers to wells. As multiphase flowmeter can detect fluid supply status of oil wells in real time, it could be a significant tool for intermittent production design.\u0000 This paper proposes a multiphase flow online measurement technology based on magnetic resonance, which can measure the production and composition of a single well in real time, with high frequency and accuracy. A set of oil well intelligent control system is developed to realize remote well open and shut in, and automatic and controllable intermittent oil production. A relationship model of well production data, open time and intermittent time is described by the machine learning-based algorithm. While the model is installed on wells, it can automatically learn and constantly refine the model to intelligently design an intermittent process.\u0000 The proposal of this technology integrates a single well from parameter measurement, data analysis to intelligent control, forming an intelligent closed-loop control of the artificial lift system. While reducing the accident rate, it has achieved maximum energy saving and efficiency improvement. This technology has achieved good results in field applications, with a power saving rate of more than 20%.\u0000 This technology is an important part of oilfield intelligence and automation and is an important step to improve the level of delicacy management of single wells and enhance the digital construction of oilfields. At the same time, the technology does not involve any information such as electrical parameters, indicator diagrams, etc. Thus, it can be extended to other forms of oil production wells other than pumping wells to improve production efficiency, save energy and reduce consumption, and realize the safe and sustainable development of oil fields.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127498916","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}