Day 4 Thu, November 18, 2021最新文献

{"title":"Monte Carlo Simulation for Uncertainty Quantification of Probabilistic Original Hydrocarbon in Place Estimation a Convergence Study How Many Samples With a Particular Sampler are Needed","authors":"Ammar Agnia, H. Algdamsi, A. Amtereg, Ahmed Alkouh, Gamal A. Alusta","doi":"10.2118/207241-ms","DOIUrl":"https://doi.org/10.2118/207241-ms","url":null,"abstract":"\u0000 It is not trivial to devise a universally accepted metric to assess the convergence of a Monte Carlo process. For the case of reservoir model, there is no \"true\" solution to compare against, so there is no choice but to reach statistical convergence if one wants to compute the expected value, standard deviation, quantiles, and so forth. Although we are lacking a reliable metric to assess convergence, looking at logarithmic plots can provide an estimate of how close one may be to a converged value. We call \"eyeball test\". The assertion that from looking at the log plot, the variation is reduced enough to confidently use the results the main objective of this work is to illustrate the potential issues of relying on non-converged Monte Carlo Simulation to estimate quantities such as the Original Hydrocarbon in place (OHIP) in the context of reservoir simulation. We will show that even in a limited-uncertainty setup, the quantiles, and the moments of OHIP as will also illustrate that the converged quantiles accurately represent the uncertainty of the system and can be used as a reduced order model for sensitivity studies.\u0000 The current work illustrates the convergence properties of a Monte Carlo Simulation used to quantify the geological uncertainty of probabilistic estimation of OHIP. We investigate the convergence behavior of Monte Carlo Simulation on 3D reservoirs model using\u0000 Two options for monitoring and stopping Monte Carlo Simulation : Post processing calculation (settlement of Statistical Moment)Automatic Realtime monitoring (Specific Error Bound)\u0000 The distributions of the moments and quantiles of the OHIP from10,000 realizations of a geological model are presented in the form of their Cumulative Density Functions. Stability of the computed moments is assessed by plotting the sample moments of the target variable evaluated at specific points as a function of the number of Monte Carlo Simulation performed. Our results suggest that the improvement in the quality of the results is significant and well worth the extra effort. For sensitivity studies, running large ensembles is still intractable but yields set of quantiles that can be used as a Reduced Order Model. The conclusions we draw are applicable to a wide range of similar 3D reservoir model. The sensitivity of Monte Carlo Simulation to the number of realizations used is often overlooked. Even though convergence studies are rare and convergence criteria hard to estimate, uncertainty quantification using Monte Carlo Simulation is an increasingly important part of static modeling workflows","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90869918","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":"Advancement Towards the Full-Field Implementation of Marmul Alkaline-Surfactant-Polymer in the Sultanate of Oman","authors":"Dawood Al Mahrouqi, Hanaa Sulaimani, R. Farajzadeh, Y. Svec, Samya Farsi, Safa Baqlani, M. Battashi, Khalsa Hadidi, O. Kindi, A. Balushi, V. Karpan","doi":"10.2118/207250-ms","DOIUrl":"https://doi.org/10.2118/207250-ms","url":null,"abstract":"\u0000 In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals.\u0000 The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected.\u0000 With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"45 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83949547","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":"Recent Case Histories of Multilateral Systems Enabling Thru Tubing Intervention in the Middle East","authors":"B. Butler, M. Kelsey, Baidy Racine","doi":"10.2118/208103-ms","DOIUrl":"https://doi.org/10.2118/208103-ms","url":null,"abstract":"\u0000 Historically, the ability to perform intervention on multilateral wells has been limited. While multilateral (ML) well construction technologies have progressed to a high level of reliability, multilateral systems that enabled intervention during the life of well had a more limited track record. Intervention outcomes after prolonged periods of production were less consistent. This lack of technologies with sufficient intervention case histories meant that generally multilateral well architecture was not selected in applications where thru tubing intervention was a requirement. In recent years, multilateral well architecture has continued to increase in demand, with more ML wells drilled and completed in the last five years than any other five-year period in the technology's history. With this increased demand has come industry enthusiasm to further mature its intervention capabilities.\u0000 This paper will review two recent case histories of separate multilateral well completion systems that enable intervention. This opens up new potential for the industry to take advantage of the cost reductions achieved with multilaterals in a much larger scope of well applications.\u0000 Two separate completion systems will be covered in this paper, System A installed in a cemented multilateral junction and system B, a completion that creates a hydraulically isolated junction via either a dual string completion or a single string completion that splits into two strings. These case histories were exectuted in 2017 to 2019, and interventions were performed after one to two years of production.\u0000 Detailed in each case study will be an overview of the equipment, the operational sequence, intervention outcome, and any lessons learned or improvements.\u0000 The systems have demonstrated themselves as a reliable method to access laterals in non-ideal downhole environments where debris is present after the well has been on production. The tubing sizes for the case studies are 3-1/2\" and 4-1/2\". In each of these wells, the following operations have been successfully performed: drift testing, acid stimulation through coil tubing and breaking of a ceramic disc. Both slickline and coil tubing have been used for the interventions and in some cases with tractors. Junction inclinations range from 1 to 43 degrees.\u0000 Plans for ongoing installations for the systems are being executed in the Middle East Region. Further, expansion of the system A capabilities by integrating it with other existing technologies is also planned. This will enable projects such as the installation of a trilateral well with flow control and intervention for each individual leg, and also the conversion of existing single bore wells to multilateral with intervention capability.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73553253","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":"Directional Radial Drilling Increases Reservoir Coverage with Precise Wellbore Placement Resulting in a Significant Production Increase from a Thin Reservoir","authors":"A. Bashirov, I. Galas, M. Nazyrov, D. Kuznetsov, A.A. Akkuzhin","doi":"10.2118/208035-ms","DOIUrl":"https://doi.org/10.2118/208035-ms","url":null,"abstract":"\u0000 In many oil and gas provinces not only in Russia, but throughout the world, carbonate strata make up a significant portion of the sedimentary cover, and large accumulations of hydrocarbons are associated with them. However, the purposeful study of them as reservoirs for hydrocarbons in our country practically began only in the post-war years. In the special petrography laboratory carbonate rocks composing various stratigraphic complexes of almost all oil and gas provinces of the Soviet Union were studied, and in particular, Paleozoic carbonate strata of the Timan-Pechora province, Ural-Volga region, Belarus, Kazakhstan, ancient Riphean-Cambrian formations of Yakutia and relatively young strata of the Late Cretaceous of the northeastern Ciscaucasia.\u0000 Carbonates are widespread sedimentary rocks. A very significant part of them was formed in the conditions of vast shallow-water marine epicontinental basins. A large number of works are devoted to the study of such deposits. However, issues related to the conditions of formation of carbonate sediments and their postsedimentary changes cannot be considered resolved, as well as the classification of the rocks themselves.\u0000 The analyzed field is the Osvanyurskoye one. It was discovered in 2007. The field is located in the north-east of the European part of the Russian Federation, 2 km from Usinsk in the Komi Republic. The field is a part of the Timano-Pechora oil and gas province and it is a mature field (fig. 1). The objective was a 2.5m thick layer of the Serpukhov horizon.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"222 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77433067","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":"Carbon Steel X65QS Pipeline Qualification for Extreme Sour Service a Global Approach: Line Pipe, Welding, Eca Methodology and Diyab Pipeline Case Study","authors":"Lam-Thanh Luc, Hamdi Saad, Matta Tanios, Dr. Al Bannay Aamer, Meer Mumtaz Ali Imtiaz Sirsimth, Remy Antoine, Thebault Florian, Ladeuille Laurent","doi":"10.2118/207232-ms","DOIUrl":"https://doi.org/10.2118/207232-ms","url":null,"abstract":"\u0000 In the wake of failures of large diameter pipelines made from plates using the Thermo-Mechanically Controlled Process (TMCP), the suitability of carbon steel material for sour environments where the H2S partial pressure is largely over 1 bar has been questioned. Understanding that seamless quench and tempered material are not prone to the same phenomenon as large diameter TMCP pipes, it has been decided to ensure the integrity of the DIYAB pipeline by qualification using the actual production environment pH=3.5 at 24°C and 6.84 bar H2S plus 6.84 bar CO2.\u0000 The global approach includes the qualification to sour service resistance under 6.84bar H2S of the base material and the welds without post weld heat treatment. Fracture toughness tests under 6.84bar H2S were also conducted, and the results fed into an Engineering Criticality Assessment (ECA) to define the Non-Destructive Testing (NDT) acceptance criteria. The NDT tools were selected for their ability to detect the critical flaws and validated. The global approach methodology and results are presented.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82098699","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":"Machine Learning in Computer Vision Software for Geomechanics Modeling","authors":"A. Noufal, Jaijith Sreekantan, Rachid Belmeskine, M. Amri, A. Benaichouche","doi":"10.2118/208049-ms","DOIUrl":"https://doi.org/10.2118/208049-ms","url":null,"abstract":"\u0000 AI-GEM (Artificial Intelligence of Geomechanics Earth Modelling) tool aims to detect the geomechanical features, especially the elastic parameters and stresses. Characterizing the wellbore instability issues is one of the factors increases cost of drilling and creating an AI-based tool will enhance and present a real-time solution for wellbore instability. These features are usually interpreted manually, depending on the experience and usually impacted by inconsistencies due to biased or unexperienced interpreters. Therefore, there is a need for a robust automatic or semiautomatic approach to reduce time, manual efficiency and consistency.\u0000 The range of Geomechanics issues is wide and interfaces with many other upstream disciplines (e.g., Petrophysics, Geophysics, Production Geology, Drilling and Reservoir Engineering). Safe and effective field operation is built on the understanding and implementation of the subsurface in-situ stress state throughout the life of the field; the quantification of key subsurface uncertainties through well thought-out data gathering and characterization programs. The integration with appropriate Geomechanics modelling and the field surveillance /monitoring strategy.\u0000 There are two major aspects that must be addressed during the design phase of any Geomechanics project. The first and most important is developing a realistic estimate of the expected mechanical behaviour of the rocks and its potential response as a result of drilling. The second is to design an economic, safe well and support method for the determined rocks behaviour. The design process begins with the feasibility study followed by preliminary design, the detail design, tender design and throughout the construction. The design is constantly updated during each phase as more information becomes available and this requires the involvement of Geologists, Engineers and Subject Matter Expert throughout the phases of a project. A central concern for all geomechanical designs is the well-rock interaction, which is not only includes the final state but also the transient effects of the well processes as well as time and stress of the dependent rock properties.\u0000 The end-to-end workflow to achieve the mechanical earth model is automated, guided and orchestrated with the help of machine learning framework such as recommendation engine for offset well data, prediction of well logs, and optimization for all calibration with existing test results, enabling end users to run sensitivity and scenario analysis so on and so forth.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80784314","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":"Inline Drilling Fluid Property Measurement, Integration, and Modeling to Enhance Drilling Practice and Support Drilling Automation","authors":"S. Roy, S. Kamal, Richard Frazier, Ross Bruns, Yahia Ait Hamlat","doi":"10.2118/208064-ms","DOIUrl":"https://doi.org/10.2118/208064-ms","url":null,"abstract":"\u0000 Frequent, reliable, and repeatable measurements are key to the evolution of digitization of drilling information and drilling automation. While advances have been made in automating the drilling process and the use of sophisticated engineering models, machine learning techniques to optimize the process, and lack of real-time data on drilling fluid properties has long been recognized as a limiting factor. Drilling fluids play a significant function in ensuring quality well construction and completion, and in-time measurements of relevant fluid properties are key to automation and enhancing decision making that directly impacts well operations.\u0000 This paper discusses the development and application of a suite of automated fluid measurement devices that collect key fluid properties used to monitor fluid performance and drive engineering analyses without human involvement. The deployed skid-mounted devices continually and reliably measure properties such as mud weight, apparent viscosity, rheology profiles, temperatures, and emulsion stability to provide valuable insight on the current state of the fluid. Real-time data is shared with relevant rig and office- based personnel to enable process monitoring and trigger operational changes. It feeds into real-time engineering analyses tools and models to monitor performance and provides instantaneous feedback on downhole fluid behavior and impact on drilling performance based on current drilling and drilling fluid property data. Equipment reliability has been documented and demonstrated on over 30 wells and more than 400 thousand ft of lateral sections in unconventional shale drilling in the US. We will share our experience with measurement, data quality and reliability. We will also share aspects of integrating various data components at disparate time intervals into real-time engineering analyses to show how real-time measurements improve the prediction of well and wellbore integrity in ongoing drilling operations. In addition, we will discuss lessons learned from our experience, further enhancements to broaden the scope, and the integration with operators, service companies and other original equipment manufacturer in the domain to support and enhance the digital drilling ecosystem.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90940984","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":"Strategies to Mitigate the Challenges of Short Circuiting in Waterflood Reservoirs with Tracers: A Case Study","authors":"Jawhara Mahrouqi, M. Chatterjee, P. Hewitt, M. Harthi, Abdulhameed Shabibi, Saif Matroushi, Yasser Al Khusaibi, Alimohammad Anbari, Said Rahbi, Rabha Omairi","doi":"10.2118/207591-ms","DOIUrl":"https://doi.org/10.2118/207591-ms","url":null,"abstract":"\u0000 Water short circuiting leading to early, sudden and massive water breakthroughs in producer wells has been a lingering concern to oil operators for many years. Unfavorable mobility ratio leading to viscous fingering, horizontal wells exhibiting ‘the heel-toe effect’ and fields with fracture-fault activities are more prone to these kinds of unwanted water breakthroughs, suffering from oil production losses and higher operational cost for management of the excessive produced water.\u0000 A brown field in the south of the Sultanate of Oman was experiencing massive water short circuiting within two of its patterns. [MJO1]While conformance was well established and dynamically confirmed through production performance and artificial lift parameters in most patterns within the field, the complicated inverted nine spot injector-producer pattern scenario[MJO2] was making it difficult to ascertain the offending injectors or unexpected flow paths leading to the condition within the study area. The lower API oil and slightly fractured and faulted geology was exhibiting conditions for injection imbalance and the challenge was to bring the high water-cut wells back to full potential and increase oil output whilst reducing water flow. To investigate the breakthrough occurrences and mitigate the challenge, chemical water tracers were introduced in the reservoir as a part of Integrated Reservoir Management framework to identify flow directions and offending injectors.\u0000 The Phase-1 of the two-phase study, discussed in this paper, was carried out to determine reservoir conformance that was contributing to short circuiting and once the cause was identified and treated, Phase-2 was carried out post well intervention to validate the success of the treatment. Phase-1 of the tracer study was initiated in October 2019 where two injectors and nineteen producers across two adjacent patterns were traced with two unique chemical water tracers. Massive tracer responses were obtained within the first few days in few wells, directly pointing out towards the offending injector(s). Sampling and analysis for Phase-1 was continued for about six months, after which, a zonal isolation was carried out in one the identified injectors in August 2020. Cement was pumped across all the perforation intervals and a new perforation was performed across the top and bottom of the reservoir avoiding the middle intervals that were taking about 70% of injection as per production logging. Phase-2 of the study was initiated in March 2021 and continued sampling and analyses are still being carried out.\u0000 With about 15% reduction in water cut and a three-fold increase in oil rate at the target producer, the study validated that an integrated knowledge of reservoir geology and production behavior coupled with tracer studies was a very successful strategy for managing short circuiting in waterflood reservoirs. The study showed that this sequence and combination of methods can be useful in effective treatment","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90371579","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":"Challenges of Hydrate Risk Management at Low Water Cuts Using Anti-Agglomerants","authors":"S. Bodnar, Zachary T. Ward, Aron Steinocher, J. Wylde","doi":"10.2118/207668-ms","DOIUrl":"https://doi.org/10.2118/207668-ms","url":null,"abstract":"\u0000 BWOLF (DH 180/185) flowlines, in the deepwater Gulf of Mexico, were being treated continuously with LDHI to manage hydrate risk. Application of the Anti-Agglomerant (AA) was being utilized to treat the asset under the initial conditions, including water cuts up to 20%, for potential unplanned shut ins. Due to a well zone change, water cut dropped from 20% to <1%. The assumption was that chemical treatment volumes for hydrate management would decrease based on water volume. However, at these lower water cuts, it was determined that higher by volume of water treatment dosing was required to provide adequate hydrate risk protection. Additionally, dead-oil circulations were periodically being used to address some pressure build up and return the system back to baseline pressures.\u0000 Rocking cell testing was conducted to determine the optimal chemical treating doses using AA alone, as well as AA + MeOH as options. However, the rocking cell equipment limitation for water cuts is ~10%, below which results have previously not been trusted. Extrapolation for estimated dosages were needed for the lower water cuts observed in the field.\u0000 Autoclave tests were done at higher water cuts (30 and 50%) to also provide data for curve fitting to confirm whether the increase need for LDHI at lower water cuts was indeed exponential in nature. Field monitoring of flowline pressures was conducted to determine treatment effectiveness. Additionally, field monitoring of water cut over time was also observed and related back to how the chemical treatment behaved in relation.\u0000 After the well zone change, application of the AA alone was not enough to effectively address the hydrate risk and resulted in gradual build up of hydrate within the system. Periodic MeOH pills were applied to reduce delta pressure, but care was necessary to avoid reaching MeOH limitations within the crude. Additionally, this method did not effectively remove hydrate formation in the flowline. Less frequently, but when necessary, dead oiling was utilized to remove the build up quite effectively. This was not ideal due to down time and deferred production. It's felt that Webber et al. correctly described the significant increase of AA dosing requirements at very low water cuts (<5%) resulting in a power function relationship. This creates further challenges such as cost of chemical treatment due to higher dosing requirements and potential water quality issues topsides when higher doses of AA are used. The data and results within confirm limited examples of where lower water cut can result in significantly increased dosing requirements for AAs and why a power function relationship should be considered when extrapolating treatment recommendations at 5% or below. There is interest in further understanding the AA requirements at low water cuts and the effectiveness of deal oiling on hydrate build up going forward. This data is particularly relevant for new deepwater projects that consider chemical use as o","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79087439","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":"Understanding the Impact of Brine Hardness on Chemical Enhanced Oil Recovery Surfactants Performance: A Data Journey","authors":"Roberto Company, S. Hocine, Baptiste Pousset, M. Morvan","doi":"10.2118/207685-ms","DOIUrl":"https://doi.org/10.2118/207685-ms","url":null,"abstract":"\u0000 Brine composition is one of the key parameters in the design of a surfactant based oil recovery process and is a condition imposed by the reservoir nature. This brine can contain a large variety of ions including monovalent and divalent cations (hardness), which impacts the surfactants solubility. Moreover, hardness evolution during the injection process can also impair surfactant formulations’ performances. Water treatment processes are useful ways to mitigate such risks, but they imply higher CAPEX for the process. As a consequence, the selection of the right surfactant will have a large impact on the cost and on crude oil production. This paper describes solution properties of the most common surfactants used in surfactant flooding i.e. Alkyl Benzene Sulfonates (ABS) and Internal Olefin Sulfonates (IOS) as a function of the brine hardness and will be compared with Internal Ketone Sulfonates (IKS), a new bio-based surfactant family.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"129 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80249899","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}