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":"Submersible Pump with Line Shaft Pump in Shallow Water, Optimum Selection for Offshore Application in the Oil & Gas Industry","authors":"Shafir Mohammed, Ibrahim Kobbia","doi":"10.2118/207881-ms","DOIUrl":"https://doi.org/10.2118/207881-ms","url":null,"abstract":"\u0000 Seawater is an essential fluid used in various process circuits, such as cooling, reinjection into the wells and utilities, etc., in the offshore oil and gas industry. Vertical pumps facilitates with lifting seawater to the platform. This study investigates and compares two pump alternatives that has been widely used in oil and gas industry for seawater lift application: Vertical line-shaft pump and Electrical submersible pump.\u0000 Existing seawater lift pump operating parameters are used as the basis of this study. The pump that is considered for the study has a flow rate of 3415 US GPM (776 m3/hr.) with a total head of 250 ft. The motor rating is 350 HP. The overall length of the pump is 21 meters. The main methodology used is a Life Cycle Cost Analysis (LCC) where the total cost of ownership of the vertical line-shaft pump and electrical submersible pump were analyzed for a period of 30 years. Furthermore, this research also addresses the operational drawbacks associated with both the pumps.\u0000 Submersible pumps have higher initial capital investment cost when compared to line-shaft pump of similar capacity and size. The energy consumption cost of submersible pumps are higher mainly owing to lower efficiencies of the motors. The power factor for submersible pumps are lower in relation to line- shaft pumps. One of the main benefits of submersible pumps are their less installation and pump pullout time. Submersible pumps occupies lower space above ground when compared to line-shaft pumps. Additionally, submersible pumps are less noisy and have lower vibration in comparison to line-shaft pumps.\u0000 This paper aims to provide key information and knowledge for engineers to make prudent decision regarding selection of the most cost effective pump for the seawater lift application with a tangible added cost value to both Capital Expenditures (CAPEX) and Operational Expenditure (OPEX).","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":"89647382","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":"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":"Fulfillment of Maintenance and Reliability Key Performance Indicators of Offshore Sites During Covid-19 Pandemic","authors":"Huda Hussein, Shamsa Al Blooshi, Waled Saeed, A. Al Salami, Masab Al Rais, Mohamed Herzallah, Mohamed Aidroos Al Wahedi","doi":"10.2118/208057-ms","DOIUrl":"https://doi.org/10.2118/208057-ms","url":null,"abstract":"\u0000 This paper addresses the challenging situation that was faced by Maintenance Teams in Offshore Sites to maintain and ensure the optimal conditions of the plants, conducting Routine Preventative Maintenance (RPM) as planned, achieving Company and Operational Excellence KPIs in the midst of COVID-19 pandemic. A brief description of how the sites defined a new normal given the circumstances to ensure all work was met while tackling the numerous obstacles in order to keep operations running smoothly is iterated below.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"115 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86793909","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":"Laboratory Evaluation Experiment for Adaptability Analysis of Nitrogen Injection in Yanchang Oil Field","authors":"Jiaxi Gao, Yuedong Yao, He Bao, Jinjiang Shen","doi":"10.2118/207275-ms","DOIUrl":"https://doi.org/10.2118/207275-ms","url":null,"abstract":"\u0000 Yanchang Oilfield conducts systematic research on nitrogen injection to enhance oil recovery. Through the research of this project, the energy supplement method of horizontal wells suitable for the study area is determined, and its injection system and process parameters are optimized and determined.\u0000 The optimal energy replenishment method selected by the mine field test achieves the following economic and technical indicators: Provide a nitrogen suitability evaluation plan; Complete the nitrogen flooding matching process design of the target well; Complete the design of the injection-production plan for the target well; Compare with other energy supplement methods.\u0000 Through the analysis of two supplementary energy methods of water injection and gas injection in indoor and similar reservoirs, the following understandings have been obtained: (1) Nitrogen is insoluble in water, slightly soluble in oil, good swelling, large elastic energy, is an inert gas, exists widely in the atmosphere, inexhaustible, inexhaustible, has a wide range of sources. (2) the recovery rate of nitrogen flooding is significantly higher than that of water flooding. (3) The field test results of water injection and nitrogen test in similar reservoirs show that the supplementary formation energy of nitrogen injection is suitable for the later development of Chang 64 and Chang 71 in the Haobasi oil field. (4) Compared with deep ultra-low permeability reservoirs, it is more economical to use nitrogen to supplement formation energy and change oil. The rate is higher.\u0000 From the above analysis, it can be seen that the supplementary energy of Chang 64 and Chang 71 reservoirs in the Haobasi oil area should be nitrogen injection as the main supplement, and water injection as a supplement. Gas/water alternate injection is used to adjust the gas injection profile to slow down the escape of injected nitrogen. . Although water injection supplements the formation energy with greater uncertainty, it can be used as a technical means of fluidity control in the gas injection process and is relatively economical.","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":"86122184","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":"Laboratory Measurements Mapping Heterogeneity and Variation of Poroelasticity for Improved Hydraulic Fracture Design in a Tight Carbonate Reservoir Onshore UAE","authors":"S. Syofyan, T. Fauzi, T. Al-Shabibi, B. Banihammad, Emil Nursalim, Nabiel Oemar Martak, Asma Hassan Ali Bal Baheeth, Joel Martin, J. Guerra, E. Muniz, A. J. Mascarenhas","doi":"10.2118/207433-ms","DOIUrl":"https://doi.org/10.2118/207433-ms","url":null,"abstract":"\u0000 Reservoir X is a thin and tight carbonate reservoir with thin caprock that isolates it from an adjacent giant reservoir. An accurate geomechanical model with high precision is required for designing the optimum hydraulic fracture and preventing communication with adjacent reservoirs. The reservoir exhibits considerable variability in rock properties that will affect fracture height growth, complexity, and width and rock interaction with treatment fluids. The heterogeneity observed from the tight sections is further complicated by the variation of Biot's poroelastic coefficient, α, which is required for accurate assessment of the effective stresses. Laboratory testing was required to characterize the extensive vertical heterogeneity for key inputs in developing a geomechanics model.\u0000 Approximately 120 ft of continuous core from an onshore field was provided for this study. The core material represented a potential tight carbonate reservoir interval and bounding sections. Heterogeneity mapping was performed from continuous core measurements from CT-imaging and scratch testing. CT-imaging provides an indication of the bulk density variation and compositional changes. Scratch testing provides a continuous measure of the unconfined compressive strength (UCS). Combining the two provides a means for accurate definition of rock thickness for dense, moderately dense, and lower density material coupled with corresponding compressive strength. Rock units were then subdivided based on these continuous properties for further geomechanics tests.\u0000 Using log analysis combined with continuous UCS measurements from scratch testing, eight rock type classes were defined covering the target reservoir interval and bounding sections. This information was used for optimizing the sample selection process to characterize each identified rock unit. Routine core analysis measurements reveal significant vertical heterogeneity with porosity ranging from 0.1% to 18.1%. Similar variability was determined from elastic properties for each of the eight rock types. Quasi-static values for Young's modulus and Poisson's ratio determined at in-situ stress conditions ranged from 2.6 to 9.6 × 106 psi, and from 0.16 to 0.34, respectively.\u0000 The Biot's poroelastic coefficient has a first-order impact on the calculated effective stress profile, which directly affects fracture stimulation model results. Testing from this study combined with previous measurements (Noufal et al. 2020, SPE-202866-MS) provides a unique correlation with porosity and bulk compressibility. In addition, rock-fluid compatibility was evaluated with proppant embedment/fracture conductivity tests. Results are dependent on a given rock type, exhibiting a wide range of fracture conductivity as a function of closure stress from 10 to 1000 md-ft. Embedment for all cases was low to moderate.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86477334","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":"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}