Day 4 Wed, December 01, 2021最新文献

{"title":"Core Effective and Relative Permeability Measurements for Conventional and Unconventional Reservoirs by Saturation Monitoring in High Frequency 3d Gradient NMR","authors":"Brian Chin, Safdar Ali, A. Mathur, C. Barnes, W. V. Gonten","doi":"10.2118/204796-ms","DOIUrl":"https://doi.org/10.2118/204796-ms","url":null,"abstract":"\u0000 A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates.\u0000 Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer.\u0000 The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon s","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83810494","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":"Satellite Fields Digitalization & ALS Optimization with EDGE & Advance Analytics Application","authors":"Nitin Johri, N. Pandey, S. Kadam, S. Vermani, Shubham Agarwal, Debashis Gupta","doi":"10.2118/204794-ms","DOIUrl":"https://doi.org/10.2118/204794-ms","url":null,"abstract":"\u0000 Data monitoring in remote satellite field without any DOF platform is a challenging task but critical for ALS monitoring and optimization. In SRP wells the VFD data collection is important for analysis of downhole pump behavior and system health. SRP maintenance crew collects data from VFDs daily, but it is time consuming and can target only few wells in a day. The steps from requirement of dyna to final decision taken for ALS optimization are mobilizing team, permits approvals, download data, e-mail dynacards, dyna visualization, final decision.\u0000 The problems with above process were: -\u0000 Insufficient and discrete data for any post-failure analysis or ALS-optimization Minimal data to investigate the pre failure events\u0000 The lack of real time monitoring was resulting in well downtime and associated production loss. The combination of IOT, Cloud Computing and Machine learning was implemented to shift from the reactive to proactive approach which helped in ALS Optimization and reduced production loss.\u0000 The data was transmitted to a Cloud server and further it was transmitted to web-based app. Since thousands of Dynacards are generated in a day, hence it requires automated classification using computer driven pattern recognition techniques. The real time data is used for analysis involving basic statistic and Machine learning algorithms. The critical pump signatures were identified using machine learning libraries and email is generated for immediate action. Several informative dashboards were developed which provide quick analysis of ALS performance. The types of dashboard are as below\u0000 Well Operational Status Dynacards Interpretation module SRP parameters visualization Machine Learning model calibration module Pump Performance Statistics\u0000 After collection of enough data and creation of analytical dashboards on the three wells using domain knowledge the gained insights were used for ALS optimization. To keep the model in an evergreen high-confidence prediction state, inputs from domain experts are often required. After regular fine-tuning the prediction accuracy of the ML model increased to 80-85 %. In addition, system was made flexible so that a new algorithm can be deployed when required. Smart Alarms were generated involving statistic and Machine Learning by the system which gives alerts by e-mail if an abnormal behavior or erratic dynacards were identified. This helped in reduction of well downtime in some events which were treated instinctively before.\u0000 The integration of domain knowledge and digitalization enables an engineer to take informed and effective decisions. The techniques discussed above can be implemented in marginal fields where DOF implementation is logistically and economically challenged. EDGE along with advanced analytics will gain more technological advances and can be used in other potential domains as well in near future.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83031529","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":"Workflow to Optimize Cluster Spacing Design of Horizontal Multistage Fractured Well in Unconventional Source Rock","authors":"Rabah Mesdour, Moemen Abdelrahman, Abdulbari Alhayaf","doi":"10.2118/204891-ms","DOIUrl":"https://doi.org/10.2118/204891-ms","url":null,"abstract":"\u0000 Horizontal drilling and multistage hydraulic fracturing applied in unconventional reservoirs over the past decade to create a large fracture surface area to improve the well productivity. The combination of reservoir quality with perforation cluster spacing and fracture staging are keys to successful hydraulic fracturing treatment for horizontal wells. The objective of this work is to build and calibrate a dynamic model by integrating geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a horizontal well drilled in the source rock reservoir using simulation and analytical models. The methodology adopted in this study covers the integration of geological, petrophysical, and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and the perforation clusters number required within a frac stage. Assuming all perforation clusters are uniformly distributed within a stage. The hydraulic planer fracture attributes assumed and the surface production measurement together with the production profile were used to calibrate the reservoir model.\u0000 The properties of the Stimulated Reservoir Volume \"SRV\" were defined after the final calibration using reservoir model including hydraulic fractures. The calibrated reservoir model was used to carry out sensitivity analyses for cluster spacing optimization and other completion parameters considering the surface and reservoir constraints. An optimum cluster spacing was observed based on the Estimated Ultimate Recovery \"EUR\" of the subject well by reservoir properties. The final results based on 70% of perforation clusters contribution to production observed from PLT log, and the results of this study were implemented. Afterwards, another study has been undertaken to increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity as an area for improvement to engineering the completion design. The methodology adopted in this study identifies the most important parameters of completion affecting well productivity for specific unconventional reservoirs. This study will help to engineer completion design, improve cluster efficiency, reduce cost and increase well EUR for the development phase.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"100 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85795127","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":"Leveraging a New Well Delivery Methodology for Stellar Drilling Results Steam Injection Project Case Study","authors":"Carlos Alejandro Terrones Brand, Miguel Alejandro Basso Mora, Rajeswary Kandasamy, Sergio Comarin, Felipe Rene Bustos Guevara, Beatriz Vega, Susana Pasaran","doi":"10.2118/204618-ms","DOIUrl":"https://doi.org/10.2118/204618-ms","url":null,"abstract":"\u0000 Mexico has set challenging oil and gas production to meet worldwide demand. In order to deliver promised oil production outputs in this challenging environment, the operator came up with efficient partnerships with key service providers to leverage resources and technical know-how whilst encouraging knowledge transfer and drilling project cost reduction. By working with various service companies, the operator creates a competitive environment where each strives to outperform the other. One such success case is in the \"S\" field, a heavy oil field producing via steam injection in the South of Mexico. Utilizing a creative design and execution methodology, the \"S\" project team succeeded to deliver improved project performance over the course of drilling the 14 wells in the campaign. The average well operational time was successfully reduced by 10%, hence maximizing the well construction index to 122 m/day and reducing overall well costs.\u0000 The main strategy to optimize performance is to re-engineer solutions for profitability such as performing a study to replace OBM by WBM, designing a new wellhead system, collaborating with the rig contractor to reduce flat time activities, redesigning cement properties for losses mitigation, improvement of ROP by merging new technologies and local practices, among others. Complementary to this, the strategy is to prioritize realistic areas of improvement by the development and utilization of a new tool called Best of the Best (BoB), a methodology breaking down all well activities in order to measure its fastest time per well and then aiming to achieve that aggressive goal. Detailed follow up in the field allows to reduce operational times by allowing the wellsite team monitor and suggest new and improved ways of doing a routine task all of which result in lower costs per foot. Utilizing this BoB approach and stringent performance monitoring while drilling (pre-actual-post) activity analysis, allowed superior performance to be achieved. The project reached a 60% improvement on well times from the first well drilled to the best performing well. The best well was drilled in 8.68 days versus a field average of 18 days (217 m/day construction index). This generated 369,000 bbls of earlier oil production, 176 days ahead vs client expectations.\u0000 Furthermore, in coordination with field staff, lessons learned were captured. But this is not enough since fast and effective communication is required, and the BoB methodology provides the solution to share optimization tricks quickly and effectively between crews, to continue well to well improvement and overall project and field level learning. Improved well delivery results is possible only by aligning the detailed planning and execution follow up in both the wellsite and a remote operations centre which monitored drilling activity in real time from town. This synergy and proactive communication system is also a key factor in the project delivery.\u0000 This paper will present th","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"81 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91512080","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":"Full-Field History-Matching of Commingling Stacked Reservoirs: A Case Study of an Oman Southern Asset","authors":"S. Aderemi, Husain Ali Al Lawati, Mansura Khalfan Al Rawahy, Hassan Kolivand, Manish Kumar Singh, C. Darous, Francois D. Bouchet","doi":"10.2118/204575-ms","DOIUrl":"https://doi.org/10.2118/204575-ms","url":null,"abstract":"\u0000 This paper presents an innovative and practical workflow framework implemented in an Oman southern asset. The asset consists of three isolated accumulations or fields or structures that differ in rock and fluid properties. Each structure has multiple stacked members of Gharif and Alkhlata formations. Oil production started in 1986, with more than 60 commingling wells. The accumulations are not only structurally and stratigraphically complicated but also dynamically complex with numerous input uncertainties.\u0000 It was impossible to assist the history matching process using a modern optimization-based technique due to the structural complexities of the reservoirs and magnitudes of the uncertain parameters. A structured history-matching approach, Stratigraphic Method (SM), was adopted and guided by suitable subsurface physics by adjusting multi-uncertain parameters simultaneously within the uncertainty envelope to mimic the model response. An essential step in this method is the preliminary analysis, which involved integrating various geological and engineering data to understand the reservoir behavior and the physics controlling the reservoir dynamics.\u0000 The first step in history-matching these models was to adjust the critical water saturation to correct the numerical water production by honoring the capillary-gravity equilibrium and reservoir fluid flow dynamics. The significance of adjusting the critical water saturation before modifying other parameters and the causes of this numerical water production is discussed. Subsequently, the other major uncertain parameters were identified and modified, while a localized adjustment was avoided except in two wells. This local change was guided by a streamlined technique to ensure minimal model modification and retain geological realism. Overall, acceptable model calibration results were achieved. The history-matching framework's novelty is how the numerical water production was controlled above the transition zone and how the reservoir dynamics were understood from the limited data.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"298 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74172721","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 Quality: The Effects of Different Separation Methods for Water and Chemical Floods","authors":"J. Almorihil, A. Mouret, I. Hénaut, V. Mirallés, A. AlSofi","doi":"10.2118/204650-ms","DOIUrl":"https://doi.org/10.2118/204650-ms","url":null,"abstract":"\u0000 Gravity settling represents the main oil-water separation mechanism. Many separation plants rely only on gravity settling with the aid of demulsifiers (direct or reverse breakers) and other chemicals such as water clarifiers if they are required. Yet, other complementary separation methods exist including filtration, flotation, and centrifugation. In terms of results and more specifically with respect to the separated produced-water, the main threshold on its quality is the dispersed oil content. Even with zero discharge and reinjection into hydrocarbon formations, the presence of residual oil in the aqueous phase represents a concern. High oil content results into formation damage and losses in injectivity which necessitates formation stimulations and hence additional operational expenses. In this work, we investigated the effects of different separation techniques on separated water quality. In addition, we studied the impact of enhanced oil recovery (EOR) chemicals on the different separation techniques in terms of efficiency and water quality. Based on the results, we identified potential improvements to the existing separation process.\u0000 We used synthetic well-characterized emulsions. The emulsions were prepared at the forecast water: oil ratio using dead crude oil and synthetic representative brines with or without the EOR chemicals. To clearly delineate and distinguish the effectiveness of different separation methods, we exacerbated the conditions by preparing very tight emulsions compared with what is observed on site. With that, we investigated three separation techniques: gravity settling, centrifugation, and filtration. First, we used Jar Tests to study gravity settling, then a benchtop centrifuge at two speeds to evaluate centrifugation potential. Finally, for filtration, we tested two options: membrane and deep-bed filtrations. Concerning the water quality, we performed solvent extraction followed by UV analyses to measure the residual oil content as well as light transmission measurements in order to compare the efficiency of different separation methods.\u0000 The results of analyses suggest that gravity settling was not efficient in removing oil droplets from water. No separation occurred after 20 minutes in every tested condition. However, note that investigated conditions were severe, tighter emulsions are more difficult to separate compared to those currently observed in the actual separation plant. On the other hand, centrifugation significantly improved light transmission through the separated water. Accordingly, we can conclude that the water quality was largely improved by centrifugation even in the presence of EOR chemicals. In terms of filtration, very good water quality was obtained after membrane filtration. However, significant fouling was observed. In the presence of EOR chemicals, filtration lost its effectiveness due to the low interfacial tension with surfactants and water quality became poor. With deep-bed filtration","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77702809","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":"Challenging the Status Quo Leads to Enhanced Drilling Performance","authors":"O. Sehsah, Oscar Bautista Sayago, Tom Newman, F. Mounzer","doi":"10.2118/204876-ms","DOIUrl":"https://doi.org/10.2118/204876-ms","url":null,"abstract":"\u0000 The technology described in this paper has been developed to challenge the shortcomings of the 40+ year old conventional blade stabilizer. The focus of this paper is to compare drilling performance on two lateral well sections against conventional spiral blade stabilizers. The comparison will highlight the noticeable improvement in drilling performance through analysis of relevant drilling parameters.\u0000 The new design stabilizer, referred to in this paper as Innovative Drillstring Stabilizer (IDS), can be positioned in the drill string as you would typically do with a conventional spiral blade stabilizer or roller reamer. The design, however, is considerably different. The opened profile, placement and contour of the blades are designed to enhance energy transfer and flow along the tool, improving the transportation of cuttings around the tool while minimizing the occurrences of balling up. The orientation and dome shape of the blades is designed to reduce friction and torque, reduce vibration, improve weight transfer and when slide drilling minimizing the occurrence of hanging up and motor stalls. The engineered drillstring stabilizer was deployed in two wells for trial and technology acceptance purpose. An 8\" OD innovative drillstring stabilizer was used as part of a steerable motor bottom hole assembly (BHA) in an integrated operations project. An in-depth performance comparison study was conducted by a specialized and independent third party between two identical BHAs. One (BHA-1), however, included conventional spiral blade stabilizers while the other (BHA-2) adopted the innovative drillstring stabilizers.\u0000 The pioneering design of the IDS in BHA-2 contributed to reducing the overall torque and aiding in better weight transfer and drilling efficiency. It was possible to apply more weight and the energy transfer to the bit, based on mechanical specific energy (MSE) calculations, showed more efficient drilling conditions. As a result, the ROP, both rotating and sliding showed significant improvement with an overall increase of more than 30%. Better stabilization with BHA-2 aided in less vibration and no motor stalls. In addition, while pulling out of hole, lower hook loads were observed due to the enhanced hole cleaning features, improved hole condition and less friction along the string components. When back on surface no indications of balling-up were observed either.\u0000 Today, drilling related inefficiencies, in the form of low ROP, non-productive time, damages beyond repair or stuck pipe and lost in hole incidents costs the oil and gas industry millions of dollars on an annual basis. The IDS is designed and proved to address such dysfunctions and improve drilling performance and efficiency while simultaneously stimulates a lower MSE drilling environment.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77862904","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":"Minimizing Carbon Footprint by Smart Sustainable Reservoir Management","authors":"Klemens Katterbauer, A. Marsala, Abdulaziz Al Qasim, A. Yousif","doi":"10.2118/204752-ms","DOIUrl":"https://doi.org/10.2118/204752-ms","url":null,"abstract":"\u0000 Sustainability and reducing carbon footprint has attracted attention in the oil and gas industry to optimize recovery and increase efficiency. The 4th Industrial Revolution has made an enormous impact in the oil and gas industry and on analyzing carbon footprint reduction opportunities. This allows classification of various reservoir operations, installation of permanent sensors and robots on the field, and reduction of overall power consumption.\u0000 We present an overview of new AI approaches for optimizing reservoir performance while reducing their carbon footprint. We will outline the significant carbon emissions contributors for field operations and how their impact will change throughout the production's lifecycle from a reservoir. Based on this analysis, we will outline via an AI-driven optimization framework areas of improvement to reduce the carbon footprint considering the uncertainty.\u0000 We analyzed the framework's performance on a synthetic reservoir model with several producing wells, water, and CO2 injecting wells. Beneficial in reducing carbon emissions from the field is the reuse and injection of CO2 for enhancing hydrocarbon production from the reservoir. One hundred different scenarios were then investigated utilizing an innovative autoregressive network model to determine the impact of these components on the overall carbon emission of the field and determine its uncertainty. The conclusions from the analysis were then incorporated into a data-driven optimization routine to minimize carbon footprint while maximizing reservoir performance. The final optimization results of the showcase outlined the ability to reduce the carbon footprint significantly.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82842083","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Field Application of Reaming-While-Drilling Technology in the Super Deep Composite Anhydrite-Salt Layers of Kuche Mountain Front in Tarim Oilfield","authors":"Zhixiong Xu, Xue-qing Teng, Ning Li, Hongtao Liu, Caiting Zhao, Bo Zhou, Bo Zou, Wei Yu","doi":"10.2118/204599-ms","DOIUrl":"https://doi.org/10.2118/204599-ms","url":null,"abstract":"\u0000 The implementation of drilling technique for multiple lithology interbeds and high-pressure anhydrite-salt in the complex Mountain Front area has been completed. The plastic creep of the anhydrite-salt layers, the losses of the low-pressure sandstone, the overflow of the high-pressure salt-water, the narrow mud density window and frequent pipe-stuck occurrence are significant issues, which trigger significant engineering challenges downhole. This study presents the application of the reaming-while-drilling (RWD) technology which has led to minimize the downhole non-productive time (NPT) and achieve successful results. The RWD technique was applied in the composite anhydrite-salt formation of the Kumugeliemu group. Through optimized combination of the RWD tools, bits, reaming blades, and the mechanical analysis the drill string with shock-absorbing design and hydraulics optimization to guarantee the bit and the reamer blades have the proper pressure drop, hydraulic horsepower and flow-field distribution, the RWD was used with the vertical seeking tool drilling technology, resulting in minimum vibration and/or stick-slip, and achieving the expected rate of penetration (ROP) as well as target inclination. It improved the operation efficiency significantly while avoiding the downhole complexities at the same time. Since the geological structure of the offset well Keshen X (no RWD) is similar to Keshen XX (RWD technology was applied), a comparison between the two wells was performed. The reaming meterage in the composite anhydrite-salt layers in Keshen XX was 791 m, spending 15 days, average ROP is 3.73 m/hr. There was no overflew or loss during the drilling. It was smooth, no pipe sticking when checking the reaming effect during the wiper trip and the tripping out. On the other hand, Keshen X spent 29 days with average ROP of 1.35 m/hr to drill the 449 m composite anhydrite-salt rock. Moreover, it was difficult to trip in and trip out during the drilling, and the pipe sticking happened frequently, back-reaming frequently as well. There were losses during both the drilling and the casing running. Due to the unsmooth wellbore, this well increased additional 3 runs of reaming after drilling operation and 4 clean-out runs. 13 days later after the reaming operation, the anhydrite-salt rock creep was checked and found that the hole was still smooth, no pipe sticking existing. Hence, RWD technology has accomplished both goals of preventing the downhole complexities and speeding up drilling. The novel RWD technology can be well illustrated by presenting all the details of its application in salt-base formations.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87452034","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 New Model for Predicting Liquid Loading in Shale Gas Horizontal Wells","authors":"Chao Zhou, Zuqing He, Yashu Chen, Zhifa Wang, A. Mulunjkar, Weishu Zhao","doi":"10.2118/204786-ms","DOIUrl":"https://doi.org/10.2118/204786-ms","url":null,"abstract":"\u0000 Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.","PeriodicalId":11024,"journal":{"name":"Day 4 Wed, December 01, 2021","volume":"74 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91484185","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}