Day 2 Tue, March 14, 2023最新文献

{"title":"How to Achieve Operational Excellence through Digital Transformation","authors":"Mahmoud Ibrahim Hegazy, K. Alsawi, Mohamed Said Atwa, Mahmoud Sayed Sayed, Mohebat Mady Bakeer, R. S. Rezk, Ahmed M. Fouda","doi":"10.2118/214140-ms","DOIUrl":"https://doi.org/10.2118/214140-ms","url":null,"abstract":"\u0000 Achieving operational excellence in oil and gas industry has a great importance due to their high impact on operational efficiency and effectiveness by proper use of human resources, process, innovation and technology which will positively support the quick decision making, eliminate wastes, maximize the system capacities, optimizing the expenditures and resources.\u0000 \u0000 \u0000 Operation Management System is an inhouse customized cost-effective software to collect, organize, calculate, allocate and analyze big data from different disciplines which helps oil and gas company operations in many ways to overcome business challenges, data management, enhance workflow efficiency, integrate between different disciplines, save time and cost. Each discipline in each company uses its own workflow and data processing technique which may leave gaps in the interconnections between them. These gaps require work duplication to cover overlap areas.\u0000 \u0000 \u0000 \u0000 Using Operations Management system achieves Generate Global database for all company assets production for better management for asset, well performance, target achievements and automatic notifications for targets over dues DFL, well tests, etc. also, allocate all wells in GIS Map for easy and quick access to well data.\u0000 It provides cost control tool over the contract by real-time allocation for actual costs and invoices. Digitalizing all the contracts data and track contract administrative. It provides a smart notifications tool for contracts list that will be expired after 6 months.\u0000 Real-time allocation for expenditures over the budget accounts directly from invoices and warehouse modules. it shows budget inception to date, Variance and forecast with option to display cost breakdown just by one click.\u0000 Smart Tool for Tracking Invoices process as per Company Cycle to make use of early payment discounts. Automatic review for invoices as per cost reference (Contract or purchase orders) and allocate actual cost directly to both budget accounts and contract.\u0000 Manages the process of administering receiving, issuing and approving the tenders of the business. It also provides access to all the tender archived data.\u0000 \u0000 \u0000 \u0000 It helps to detect problems sooner, boost collaboration and improve responses, for safer, more reliable, and more efficient operations.\u0000","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124545103","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Hydraulic Fracturing Sensitivity to Water Injection Volumes In Wolfcamp Formation","authors":"Y. Saeed, M. Alhajeri, Reza Barati Ghahfarokhi","doi":"10.2118/214112-ms","DOIUrl":"https://doi.org/10.2118/214112-ms","url":null,"abstract":"\u0000 Hydraulic fracturing is a common stimulation technique in oil and gas production to stimulate wells with low permeability. An optimum fracture half-length is designed by injecting the right amount of fracturing fluid to achieve successful results. Otherwise, injecting lower than the optimal amount will cause a poor fracture network, water blockage, and phase trapping of oil and gas behind the fracture space while over injection may result in frac hits and unfavorable economics. This paper presents the importance of the optimum fracture half-length and the role of injection volumes to generate such a length. CMG models were created to study the correlation of different parameters during hydraulic fracturing in the Wolfcamp formation (Permian basin): fracture permeability, water saturation, and capillary pressure. Three CMG models with different fracture half-lengths of 100ft, 200ft, and 350 ft were created. Sensitivity analysis of facture permeability was performed on each model using different values, e.g. 0.1, 1, 10, and 100 md. Representative cases were selected based on the sensitivity analysis results on fracture permeability. Fracture permeability was then changed in each model and was 5 md for the first model, 10 md, and 20 md for the second and third models, respectively. The effect of water saturation was also studied by changing the water saturation from 45% to 55% in an increment of 5% in each simulated model. Finally, the capillary pressure data was added to each model to study the effect of water blockage. Economic analysis was studied to determine the best-case scenario in terms of higher NPVs and RORs. Sensitivity analysis of facture permeability indicated that as fracture permeability increases, then an increase in hydrocarbon production is achieved in which the water saturation was the conclusive parameter. For instance, hydrocarbon production rates were the lowest in the first model which had the lowest fracture half-length and, therefore; fewer water volumes were injected. The second model with a fracture half-length of 200ft as the optimum length provided the optimal amount of injected water and gave the highest amount of incremental Hydrocarbon production, i.e. water saturation and fracture permeability were higher than the previous one. The last model, which has the highest fracture half-length and also the highest amount of injected water showed a significant amount of formation damage. A higher amount of injected fluids caused a high capillary pressure that was responsible for blocking the fractures and caused a decrease in relative permeabilities. The amount of injected water during hydraulic fracturing will significantly affect oil and gas production. CMG models, decline curve analysis, and economic studies showed that designing the optimum amount of injection volumes is key to a successful hydraulic fracturing treatment and minimizing the risk of causing any damage to the formation.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125071405","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":"Deliberate Selection of Wellbore Flow Profiling Technology","authors":"A. Tveritnev, Douglas A. Boyd, Ahmed Saber Abdel Aziz","doi":"10.2118/214220-ms","DOIUrl":"https://doi.org/10.2118/214220-ms","url":null,"abstract":"\u0000 Wellbore production / injection flow profiling provides key information for reservoir production and hydrocarbon recovery management. To collect wellbore liquid / gas flow profile data, ADNOC's Onshore Engineers utilise three proven technologies; Production Logging Tools (PLT), Fiber Optical Downhole Temperature Sensors (DTS) and Inflow Chemical Tracers (ICT) placed on the completion. Each technology utilises different physics and has unique implementation requirements. The optimum monitoring technology is selected at the well planning stage with considerations to well design, completion type, fluid type, well purpose (injector or producer), economics, technology reliability, installation / data collection operational considerations, expected lifetime, interpretation confidence, field maturity and field monitoring strategy. Each monitoring option might be applicable under certain operational and well construction constraints, and provide results within required uncertainties. This paper shares ADNOC Onshore's guidelines for the selection of the most appropriate flow monitoring technology for its oil and gas reservoirs developed primarily with horizontal wells and water injection for pressure support.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"90 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131830535","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":"Strategic Modelling Approach for Optimizing and Troubleshooting Gas Lifted Wells: Monitoring, Modelling, Problems Identification and Solutions Recommendations","authors":"Ahmed Maher Ali, Mohamed Nagy Negm, H. Darwish, K. Mansour","doi":"10.2118/214053-ms","DOIUrl":"https://doi.org/10.2118/214053-ms","url":null,"abstract":"\u0000 Offshore gas-lifted wells are challenging due to the numerous factors affecting performance, starting from the surface gas compression facility to reservoir performance. Mature oil fields add more challenges due to many flow assurance and mechanical problems. Real-time well monitoring is a must for early problem identification. Also, performance modeling is powerful and helpful for identifying and rectifying problems early. The work here emphasizes an optimization strategy for offshore gas-lifted wells.\u0000 This paper introduces cases of offshore problematic gas-lifted wells and their full optimization and problems solving strategy to be utilized as an integrated approach for solving the problems of similar problematic gas-lifted wells in any field. The recommended strategy depends on studying problematic gas-lifting wells covering some commonly encountered problems. The recommended remedial actions for the selected problematic cases in this intensive study resulted in precious oil gains, cost savings, and gas lift usage optimization. The solution combines surveillance, multiphase simulation, data analytics, and operations.\u0000 This paper discusses three major problems and the strategy to solve them: the first is wells with erroneous surface gas measurement and excessive gas injection; the second is unstable gas-lifted wells, and the third is optimizing low reservoir deliverability gas-lifted wells. In addition, other individual optimization cases, including integrated full-field cases, are introduced for the recommended strategy's completeness. This comprehensive study finds that the optimum approach for rectifying most gas-lifted wells problems must start with real-time monitoring, then modeling the case, and end by recommending possible solution scenarios and their impact on optimizing well performance.\u0000 This study brings the significance of surveillance and dynamic simulations in the overall production cycle: planning to operations. Further, dynamic simulations also help arrive at operators’ guidelines on avoiding failed start-ups and ensuring stable operation. Finally, the power of integration between different disciplines is shown by incorporating several subsurface and surface information in the uncertainty study.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"460 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131857054","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":"Post-Waterflooding Oil Reservoir Surveillance Using Pulsed Neutron Well Logging in Upper Burgan Formation, Northern Kuwait","authors":"Yonghwee Kim, Khaled Jamal Ibrahim Al-Quoud, M. Sahib, E. Sergeev","doi":"10.2118/214263-ms","DOIUrl":"https://doi.org/10.2118/214263-ms","url":null,"abstract":"\u0000 Operators commonly adopt waterflooding as a secondary recovery method to maintain reservoir pressure and displace remaining oil for production enhancement. Effluent and seawater have been injected into the Upper Burgan formation, which contains multiple layers of sand reservoirs, in the North Kuwait Raudhatain field. Well-based surveillance to understand post-waterflooding hydrocarbon distribution is essential for new perforation additions.\u0000 Formation saturation monitoring for cased wells is widely performed with pulsed neutron well logging techniques. Pulsed neutron well logging provides time-based thermal neutron capture cross-section (i.e., sigma log) and energy-based element-specific ratios (i.e., carbon/oxygen (C/O) logs). Formation water salinity must be known and high to use sigma data to quantify formation fluids. When formation water salinity becomes a variable due to effluent and seawater injection, sigma log-based saturation analysis is not applicable. A salinity-independent measurement that distinguishes between oil and water is required; consequently, a C/O log must be used to obtain saturation profiles in mixed-water salinity reservoirs.\u0000 The Upper Burgan formation’s initial water salinity in the Raudhatain field is high (i.e., approximately 220-240 kppm NaCl equivalent); thus, water saturation computation was performed with a sigma log. After the injection of effluent and seawater (mixed-water salinity ranges from 50 kppm to 170 kppm) was started, formation oil volumes must be evaluated using C/O logging. A well-specific Monte Carlo Neutron Particle (MCNP) model and two-detector-balanced C/O data sets were combined to compute oil saturation.\u0000 We demonstrate multi-well case examples delineating well-based formation saturation profiles in post-injection reservoir conditions. A comparison of sigma- and C/O-based saturation analyses revealed water-flooded zones. Time-lapse sigma data sets highlighted how the water injection impacted thermal neutron capture cross-section measurements. Additionally, multi-detector, time-based nuclear attributes were used to evaluate formation properties and the presence of hydrocarbon-bearing sands. Following pulsed neutron log interpretation, subsequent add-perforation activities were performed; consequently, by-passed or remaining hydrocarbon was successfully produced.\u0000 Evaluation of current formation fluid distribution in areas of the field where mixed-water salinity exists is challenging. Integrating sigma, C/O, and auxiliary pulsed neutron logs determined the remaining formation oil distribution and volume. The optimized perforation strategy to maximize oil production from existing wellbores was executed.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125434398","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Shale Wettability Alteration upon Exposure to Surfactants","authors":"A. Alzaabi, A. Adila, Md. Motiur Rahman, Mujahid Ali, A. Keshavarz, S. Iglauer, M. Arif","doi":"10.2118/214108-ms","DOIUrl":"https://doi.org/10.2118/214108-ms","url":null,"abstract":"\u0000 The development of unconventional resources such as shales has gained great popularity in the past decade. The objective of this study is to investigate the effect of surfactants on the wettability of shale rocks. In particular, we examine the influence of different concentrations of CTAB and SDBS surfactants on Eagle Ford, Wolf Camp and Mancos shale samples to determine their wettability alteration potential at the macro-scale.\u0000 In this work, macro-scale contact angle (CA) measurements of the three studied shale samples were conducted at ambient conditions as a function of surfactant concentration. Additionally, rock surface imaging was conducted via Atomic Force Microscopy (AFM) and Scanning Electron Microscopy (SEM) at the nano- and micro-scale respectively. Surface chemistry was also investigated through zeta potential and Fourier-transform infrared spectroscopy (FTIR) analysis to understand the interactions at the surfactant-mineral interface and its associated impact on wettability alteration.\u0000 The results indicate that the wettability alteration potential of surfactants on shale surfaces is closely related to rock minerology, while it is a relatively weak function of surfactant concentration. The contact angle results of Eagle Ford and Wolf Camp indicate mixed-wet conditions, while Mancos indicates water-wetness. The contact angle results at high pressure show that the increase in pressure leads to contact angle increase. The results also show that zeta potential results for all shales tends to increase in magnitude as the concentration of both surfactants increase. Additionally, FTIR results indicate the presence of C-O (carboxylate group), Ca-C, and Si-O bonds on the surfactant-treated surfaces at different extent. Finally, surface topography images revealed that Eagles ford and Wolf Camp have a relatively higher surface roughness compared to Mancos.\u0000 This study aims to develop scientific understanding of the different shale compositions and surfactant wettability alteration of shale rocks from a micro-scale perspective.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125472830","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":"High Resolution Discrete Fracture Network Application for Polymer Flooding Design in a Naturally Fractured Carbonate","authors":"Diego Nicolas Corbo, R. Lathion, F. Games, V. Martinuzzi","doi":"10.2118/214091-ms","DOIUrl":"https://doi.org/10.2118/214091-ms","url":null,"abstract":"\u0000 Despite their higher complexity (Juri et al., 2015) and usually more challenging commercial development, naturally fractured reservoirs account for a significant portion of oil and gas reserves worldwide (Sun et al., 2021). Typically, natural fractures tend to enhance the productivity of the wells, yet they also tend to accelerate reservoir depletion, often leading to sub-optimal field production and leaving significant volumes of hydrocarbons behind (Aguilera, 1995). In this work, we propose a specific polymer injection design that can provide the conditions for fracture-matrix counter-current flow to develop in a naturally fractured carbonate reservoir. In turn, this flow could trigger a virtuous cycle where the displacement front is progressively slowed down, increasing the efficiency of the displacement process and the oil recovery. This study focused on the integration of multiple sets of data to characterize karstic and tectonic fractures in a discrete fracture network (DFN) model and its posterior use in a dual medium simulation model to determine polymer flooding optimal spacing and injection strategy in a complex, naturally fractured carbonate system.\u0000 An innovative and integrated approach combining 3D seismic data, bore-hole imagery (BHI), cores, and production data was applied to characterize and represent karstic features. The applied workflow consisted of (1) identification and manual picking of karstic features on BHI, (2) deterministic picking of karstic features as geobodies on the 3D seismic (enhanced similarity volume), (3) integrated implementation of the karstic features into the geological model using advanced geostatistical methods (Multi-Points Simulation, or MPS), and (4) implementation of resulting enhanced reservoir properties on a fit for purpose high-resolution dynamic model (dual porosity/dual permeability).\u0000 Multiple simulations were run to evaluate different sensitivities including injection rates, injection strategy, completion approach, and producer-injector pattern spacing. Particularly for the latter, a robust karst/fracture system characterization was critical to propose optimal pattern sizes which aim to simultaneously avoid early polymer breakthrough -in shorter than optimal designs and minimize potential shear thickening degradation effects tied to higher polymer throughput required by excessive producer-injector distancing. In terms of the completion interval, the DFN-derived properties were also strongly conditioning the selection of the injection interval with noticeable effects and contrasting results. Because of the superposed features constituting the total fracture system and their different origins, a field-level comprehension of anisotropy and local intensity of the fractures is critical for selecting both the wells for the injectivity test and the potential area for the pilot in the next stage of the project.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126630262","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Modelling Approach of Optimum and Effective Well Length Evaluation for MRC Development Strategy.","authors":"A. Shbair, Djamal Kherroubi, Ian Bosivert, F. Noordin, Raphael Melo, Khalid Mohammed Abdalaziz","doi":"10.2118/214194-ms","DOIUrl":"https://doi.org/10.2118/214194-ms","url":null,"abstract":"\u0000 Maximum Reservoir Contact (MRC) drains have been introduced and implemented as an attractive solution in reservoir developments to accelerate production/injection while optimizing the development costs. The main objective of this paper is to provide a workflow to assess the optimum well length (Lopt) and MRC wells evaluation. In addition, it aims to highlight the factors affecting actual Effective well length (Leff) based on a study performed on a giant oil field and the planned execution plans to mitigate wells with poor effective well length.\u0000 A new approach is proposed to predict the optimum well length based on the proportionality of flux rates and productivity index (PI). The approach uses steady-state well modelling packages built using the static well data such as trajectories, reservoir/fluid properties, vertical and lower completion tuned with dynamic data such as surface well test data and downhole P& T measurements. Output results are oil influx rates along the trajectory, PI and production profiles. For the sensitivities, an automated well model base calculation was implemented through an Excel-Macro to facilitate performing different realizations of wellbore design, permeability ranges, and tubing sizes. Next, the evaluation of horizontal wells was assessed utilizing surveillance tools with the integration of the several factors affecting the effective well length.\u0000 Prior to implementing MRC drilling, the asset team must assess the optimum well length (Lopt) for their reservoir settings where a certain limit for horizontal section indicates an increase in frictional losses and increment (Q, PI) is no longer favorable. Theoretical models indicate productivity and rates proportionality with horizontal length. While field case evidence of wells surveillance show effective length is rarely 100%. The findings proved the tool's efficiency to predict Lopt with the capability to reduce simulation runs/efforts for multiple scenarios. For the studied reservoirs, the Lopt was inferred to be in the range of 9000 up to 16,000 ft depending on the permeability, fluid properties, completion size and surface back pressure. Tubing diameter size was found to have a major influence on the flux rate, while wellbore diameter had a negligible impact. The workflow assessment on field studies with average conventional wells and MRC wells length of 1800 ft-10,000 ft inferred significant factors affecting actual well effective length to be: Well placement (Porous/dense), Heel-toe effects, Damage while drilling, production/Injection rate, Barefoot vs. completion, acid Stimulation after drilling, Well accessibility due to hole condition and production rate limits (Spinner threshold).\u0000 The tool will help in the preliminary assessment to decide the optimum well length for the MRC, considering the reservoir settings and multiple completion options. In addition, the application can be extended to integrate with dynamic simulation as a robust tool to optimize compl","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129432112","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":"Retrievable Socket Electronic Memory Recorder as a New Method of Bottom Hole Pressure and Temperature Survey in a Mature Field","authors":"Luthfan Nur Azhim, Satria Pratama, I. G. N. Aryawan, Angga Pranata, Wan Renaldo, Diandra Aullia, Agung Wibawa, Guntur Mulyanagara, Anang Arie Kuncoro","doi":"10.2118/214211-ms","DOIUrl":"https://doi.org/10.2118/214211-ms","url":null,"abstract":"\u0000 This paper presents valuable new method from Pertamina Hulu Rokan Zona 4 in bottom hole pressure and temperature (BHPT) survey. Nowadays, the conventional method and gradient pressure acquisition is only able to be done by using slickline after swabbing job, because during swabbing job, the swabbing tool string is used inside the tubing. Unfortunately, there are missing data when influx from reservoir occurred, due to the shut-in condition may not always represent overall characteristic of well.\u0000 Retrievable Socket Electronic Memory Recorder (Retrisock EMR) is consisted of seating parts with deliverable and retrievable mechanisms. Engineering design was done to ensure it compatible for acquiring data during swabbing job without slickline unit. Retrisock EMR is put inside tubing, it is possible to record data since run in hole tubing, pressure test packer, swabbing job, pressure build up and static gradient pressure temperature. It could be retrieved without pull out tubing from well to download the data, nevertheless, the data may be uncertain for further analysis. The advantage, it could be put back into tubing by using sand line rig.\u0000 Pressure and temperature were obtained during swabbing job represent the influx from reservoir into well. The graph of pressure can be approached as a well test, such as modified isochronal test which can be processed to pressure transient analysis for further determination of skin value, reservoir boundary and permeability. Combination of fluid total volume during swabbing job and pressure transient analysis result become reference whether well stimulation is needed or not, before putting on production well. Result of static gradient pressure analysis will estimate the static fluid level also could be used as measured gradient of fluid in well for calculating inflow performance relationship (IPR) precisely. The result of implementation in Talang Akar Formation, Benakat Barat Structure, well BKB-272 increased production significantly from 600 BFPD to 800 BFPD after evaluated by using data from Retrisock EMR measurement. Two more promising benefits of Retrisock EMR are time and cost efficiency. Based on study and implementation, it can reduce operation time up to 10 hours. Then, the impact of faster operation time is less operation cost\u0000 Tool and method presented in this paper provide valuable concept for well optimization in developing BHPT survey before and after stimulation to compare the reservoir influx without pull out tubing string and slickline. Another opportunity is BHPT survey without shut in the well in oil well producer while it on production by using artificial lift electric submersible pump (ESP) that was not equipped with downhole sensor as real time monitoring tool.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125980370","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":"Engineered Bit Design with New Cutter Technology Improved Drilling Efficiency in Abrasive Sandstone in China Ordos Basin","authors":"Yongjun Liu, Jinsong Li, Dong Lin, Jiacai Sun, Lei Luo, Guiyang Chen, Peng Li, Peng Ding, Zhiqiang Chen, Yang Xia, Rui Xiao","doi":"10.2118/214139-ms","DOIUrl":"https://doi.org/10.2118/214139-ms","url":null,"abstract":"\u0000 Dual lateral horizontal wells were drilled for China Changbei tight gas development in Ordos basin. The horizontal 8 ½\" hole section is the most challenge part for efficient well construction due to the hardness and abrasiveness of the consolidated sandstone rocks. Optimized drilling performance requires the matching of appropriate drill bit technology to an application for the formation to be drilled, which can be an engineering challenge. Various types of drill bits, including TCI, PDC and Hybrid type bits are used in Changbei for continuous performance improvement.\u0000 The 8 ½\" hole section consists of hard and abrasive sandstone, interbedded claystone, and conglomerates. Most drill bits suffered short runs due to severe wear in the outer region of the bit including Gauge and Shoulder area, even lost cones for TCI and Hybrid bits.\u0000 With collaborations from operators and bit vendors, based on dull review and data analysis, a new type of PDC bit was designed with advanced cutter technology. The new design was developed to increase ROP and run length, avoiding unnecessary trips in the challenging formations and improved the drilling efficiency.\u0000 The new designed PDC bit adopted short profile design, reversed circle cutter placement pattern, balanced the aggressiveness and durability with backup cutters and DOC control. PDC cutters was used for passive gauge protection to overcome the wear out due to formation abrasion.\u0000 The field trials were very successful. The new designed PDC bit improved 30% on ROP and 10% on footage per bit run than offset Hybrid bits. Moreover, the new designed PDC bit eliminated lost cone risks of TCI and Hybrid bits, which was happened a couple of times in Changbei and caused tremendous NPTs for fishing and sidetracks.\u0000 This article will describe the bit performance improvement journey of Changbei tight gas field. Even with a long period of time staying on plateau, step changes still possible with new technology deployment and continuous improvement mindset.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121839240","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}