Day 2 Tue, March 14, 2023最新文献

{"title":"Data Analytics Drives Production Optimization for Gas Lift Wells to the Peak, Case Study from Gulf of Suez.","authors":"M. Koriesh, Mahmoud El Sheikh, Ahmed Maher, M. Elwan, Ahmed El Bohoty, Hisham Mousa","doi":"10.2118/213974-ms","DOIUrl":"https://doi.org/10.2118/213974-ms","url":null,"abstract":"\u0000 Gas Lift has been applied in the oil field for more than 70 years, despite the new technology and developments there is always more optimization that can be done. In this paper we are giving a leading example of one of the oldest gas lift projects in gulf of Suez that has been running for more than 50 years where 540 MMSCFD being pumped on daily basis to produce more than 200 wells as of today. the experience in this field is quite historical but the question is always persisting are we making best use of lift gas volumes and pressure, does every well have the optimum design and receives the optimum gas lift rate. One more important question will be how to prioritize interventions and optimization operations to target wells with highest value.\u0000 In order to assess the overall gas lift performance of the field an innovative dashboard was created including Key performance indicators that reflect benchmarking of Lift Gas Consumption compared with historical Performance of the field. This should spot the light to the field with lowest efficiency and most probably it is expected higher return of production if we dedicate efforts to this field.\u0000 Moreover creating wells dashboard has valued new Key Performance indicators with New Diagnostic Graphs that was not given attention by the industry before. Having these diagnostic Plots allowed benchmarking performance of wells for similar reservoir, completion type, gas lift design and sand face completion. Using this technique, it became easy to detect wells with higher potential of production with proper gas lift intervention.\u0000 Although Analytics can give some guidance on the required actions to enhance production of wells knowing the basic design, having the analytics coupled with Integarated Network modelling and well models added more value to the project.\u0000 Data Driven Gas Lift Optimization approach was applied since Oct. 2021 in an extensive approach over GOS, the approach succeeded to define more than 74 Optimization and Intervention Opportunities 45 of them were actually intervened in less than a year and added more than 4000 BOPD to production capacity. It was not a surprise that some of historically known underperforming wells were interpreted underperforming for other reasons than gas lift in-efficiency but using Gas lift Analytics re-analysis of the system showed huge value for gas lift intervention in these wells and succeeded to revive them.\u0000 Data Analytics and Data driven gas lift optimization is proved a huge leap in managing gas lift fields and keeping the system running closer to optimum.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"135 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115263013","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":"Using Cerium Oxide (6.0 SG) as Weighting Material in HTHP Drilling Fluids","authors":"G. Soori, Mohd Azrul Mohd Alwi, Zaa'Eleezia Haniff Julian, Nazeeya Tajudin, Shahrul Azwan Zulkifli, Noor Amirah Abd Rahaman","doi":"10.2118/214171-ms","DOIUrl":"https://doi.org/10.2118/214171-ms","url":null,"abstract":"\u0000 In high-density drilling fluids, maintaining low plastic viscosity (PV) to reduce Equivalent Circulation Density (ECD) and consequently achieve a higher rate of penetration comes with its own challenges. A low PV indicates that the drilling fluid is capable of drilling faster due to the low viscosity fluid exiting at the bit. PV represents the viscosity of drilling fluids when they are extrapolated to an infinite shear rate based on the Bingham model.\u0000 High PV is caused either by a viscous base fluid or by an excessive solid content in drilling fluids. The usage of a new product, Cerium Oxide (CeO2) with S.G at 6.0, referred to as CERITE in this paper, has been evaluated in a HTHP drilling fluid.\u0000 CERITE allows the drilling fluid to achieve higher density where the solid content in the mud is much lower than traditional weighting materials that are added to the drilling fluids.\u0000 A drilling fluid THAT IS formulated with CERITE as weighting material has a lower solids content due to the higher S.G. of CERITE and thus contributes to effective management of ECD without needing to restrict the drilling rate compared to drilling fluids that have been weighed up using API Barite\u0000 The objective of this study is to discuss the performance of a HTHP drilling fluid where CERITE has been used as a weighting material. Hence, two batches of HPHT water-based mud (WBM) with a density of 2.0 SG, one containing API standard Barite and the other CERITE, were compared. HPHT filtration is measured under static conditions at 400 °F and 500 psi. A Particle Plugging Apparatus (PPA) is used at 2000 psi differential pressure for measuring the filter cake sealing capability on a ceramic disk. The rheological properties, particle size distribution (PSD), sag tendency, the volume of filtrate, and the filter cake thickness of the drilling fluids are measured after hot rolling the mud at 400 °F for 16 hours. Circulation hydraulic and frictional pressure loss measurement using rheology model as Power-Law is simulated to evaluate the effects of this product on equivalent circulating density (ECD) reduction against the API Barite.\u0000 This paper discusses the extensive lab test results for the performance of CERITE against API Barite that has been added in a HTHP WBM system and ultimately concludes suitability of this material as a weighting agent.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"204 ","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120930654","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":"Numerical Investigation of Hybrid Carbonated Smart Water Injection (CSWI) in Carbonate Cores","authors":"A. Hassan, E. Al-Shalabi, B. Ghosh, B. N. Tackie-Otoo, M. Ayoub, Imad A. Adel","doi":"10.2118/214163-ms","DOIUrl":"https://doi.org/10.2118/214163-ms","url":null,"abstract":"\u0000 Carbonated smart water injection (CSWI) is a potential hybrid EOR technology under development. The process involves dissolving CO2 in smart water ripping the benefits of the synergic effect of CO2 injection and smart water. Based on the experimental laboratory data, including core flood experiments, this paper presents numerical investigations of the combined impact of dissolving carbon dioxide (CO2) in smart water (SW) on oil recovery in carbonate cores. An advanced processes reservoir simulator was utilized to build a core-scale model. Both the physics of smart water flooding as well as CO2-gas injection were captured. The generated model was validated against the coreflooding experimental data on hybrid CSWI, including cumulative oil production (cc) and oil recovery factor (%). The Corey's correlation relative permeability model was used for capturing the multiphase flow. The numerical model was used to understand the underlying recovery mechanisms and crude oil-brine-rock interactions during CSWI. The model was further utilized to perform sensitivity analysis of different parameters and to optimize the CSWI design.\u0000 Based on the numerical results, the experimental coreflooding data were accurately history-matched using the proposed model with a minimal error of 8.79% applying the PSO-based optimization method. Moreover, this history-matched model was further used for sensitivity analysis and optimization of the CSWI process. The objective functions for sensitivity analysis and optimization are based on minimizing the history-matching global error and maximizing oil recovery. The optimized design was achieved by performing a sensitivity analysis of various input parameters such as oil and water saturations (Soi and Swi), DTRAP (i.e., relative permeability interpolation parameter). On the other hand, in terms of maximizing the oil recovery while minimizing the usage of injected CSW solutions during CSWI, the optimal solution via the PSO-based approach achieved a cumulative oil recovery of 55.5%. The main mechanism behind additional oil recovery with CSW is due mainly to wettability alteration and ion exchange between rock and brine. Additionally, CSWI was found to be more efficient in releasing trapped oil compared to waterflooding, indicating the synergic effect of dissolved CO2 in SW solutions. Based on this research, the envelope of CSWI application in carbonates for CO2-storage is expected to expand. This study presents one of the few works on numerical modeling of the CSWI process and capturing its effects on oil recovery. The optimized core-scale model can be further used as a base to build a field-scale model. This promising hybrid CSWI process under optimum conditions is expected to be economical and environmentally acceptable, which promotes future field projects.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122672953","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":"Geochemical Interactions Among Rock/CO2/Brine Systems: Implications for CO2 Geo-Storage","authors":"A. Adila, A. Raza, Yihuai Zhang, Mohamed Mahmoud, M. Arif","doi":"10.2118/214029-ms","DOIUrl":"https://doi.org/10.2118/214029-ms","url":null,"abstract":"\u0000 Carbon Capture and Storage (CCS) is one of the promising techniques to mitigate carbon dioxide emissions and move towards net zero targets. The efficiency of a geological storage process is, however, a complex function of CO2/rock/brine interactions. In particular, the effect of geochemical interactions among CO2/rock/brine systems in an aquifer and its associated impact on wetting behavior has not been rigorously investigated before.\u0000 In this work, we study the effect of the critical parameters affecting the CO2/rock/brine system wettability from a geochemical perspective. In particular, we study the effect of temperature, pressure, and salinity on the wettability of the CO2/calcite/brine system. The wettability was assessed based on the disjoining pressure, which was calculated from calcite surface potential. The geochemical simulator used is based on surface complexation modeling and takes dissolution and precipitations reactions of the minerals and aqueous species into account.\u0000 The results show that increasing pressure decreases the concentration of calcite surface species >CaOH2+ and >CO3−, while it increases the calcite surface species >CaCO3−. However, increasing temperature increases the concentration of calcite surface species >CaCO3− and >CO3−, while it slightly decreases the calcite surface species >CaOH2+. The results also show higher calcite surface potential and disjoining pressure at higher temperatures and lower salinity, which reflects an increase in water wettability (or a decrease in CO2-wetness) and greater CO2 storage potential in calcite-rich aquifers at these conditions.\u0000 This paper provides insight into the effect of different influencing parameters on the CO2/rock/brine interactions and CO2/rock/brine wettability, which can help understand the geochemical processes involved in CCS projects under a wide range of operating conditions.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114284295","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":"Well Testing Analysis Methodology and Application for Complex Fault-Block reservoirs in the Exploration Stage","authors":"Changlin Liao, Ruifeng Wang, Juntao Zhang, Qizhi Huang, Xiangling Li, Xuerui Zheng, Zimo Lin","doi":"10.2118/214186-ms","DOIUrl":"https://doi.org/10.2118/214186-ms","url":null,"abstract":"\u0000 A complex fault-block reservoir usually has large layer span, many thin layers and oil-water systems. The available data are limited in the exploration stage. One of the biggest advantages is that each well is tested several times. Based on comprehensive geological study, this paper proposed a well testing analysis methodology to carry out reservoir evaluation, and the results are applied to the oilfield development plan. Well testing can reflect the static and dynamic characteristics of reservoir at the same time. It shows high application value in the exploration stage. The analysis methodology of well testing in complex fault-block oilfield mainly includes three aspects: (1) Establish a novel calculation method to obtain crude oil parameters of all tested intervals, which are necessary in well test interpretation. (2) Build reliable interpretation models to evaluate wellbore, formation property, productivity and boundary according to pressure derivatives curves. (3) Propose a concise evaluation process to show reservoir characteristics in both vertical and plane. This methodology is applied in Doseo Oilfield and proved to be a great methodology in complex fault-block reservoirs. The calculated crude oil parameters are good matched with limited PVT data. The errors are less than 10%. The formation characteristics obtained from the models including permeability, faults and aquifer energy are well verified by seismic and well-logging interpretation. The reservoirs in middle area on the plane and Zone K in the vertical show high productivity and permeability. They can be selected as the key oil regions for the first production. Similar formation characteristics are reflected by the analogous shape of pressure derivatives. They can be put into production with the same development methods to obtain higher benefits. The innovation is that this paper proposes an analysis methodology of well testing to calculate right crude oil parameters, identify formation characteristics and key oil regions, and find similar reservoirs. It can decrease the errors which are caused by parameter uncertainties and multi-solution of interpretation models.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128768843","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":"Optimization Design of CO2 Pre-Pad Energized Fracturing for Horizontal Wells in Shale Oil Reservoirs: A Case Study of the Ordos Basin","authors":"Yuxiao Zang, Haizhu Wang, H. Abderrahmane, Bin Wang, Tianyu Wang, S. Tian, S. Stanchits, A. Cheremisin","doi":"10.2118/214142-ms","DOIUrl":"https://doi.org/10.2118/214142-ms","url":null,"abstract":"\u0000 An improved recovery technique using carbon dioxide (CO2) pre-pad energized fracturing is presented to address the issue of low recovery in depleted development of shale reservoirs in the Ordos Basin. This study quantitatively evaluates the effect of CO2 pre-pad energized fracturing under different engineering and geological parameters. The geological model of the target block was created in GOHFER using field logging data from the Ordos Basin oilfield. By coupling the reservoir simulator CMG, a three-dimensional wellsite-scale long horizontal mechanism model was established, considering the artificial hydraulic fracture model. The influence of engineering parameters and geological parameters on CO2 distribution was quantitatively evaluated.\u0000 According to the outcomes of the simulation, the production potential of shale oil reservoirs can be significantly increased by using the CO2 pre-pad energized fracturing development method. Important engineering factors affecting the stimulation include the CO2 injection volume and soaking time, and the geological factors include the porosity, permeability, and layering. When the injection amount reaches a certain level, the growth of CO2 sweep area decreases. With the increase of immersion time, the CO2 sweep range gradually increases. Reservoir porosity and permeability affect CO2 sweep in the lateral direction. Considering the front slick water fracturing fractures, the impact on the CO2 sweep range is not apparent.\u0000 Combined with GOHFER and CMG numerical simulation software, this study can realize the refined description of reservoirs considering artificial hydraulic fracture networks. According to the CO2 injection range, the effect of CO2 pre-pad energized fracturing under different engineering and geological conditions can be quantitatively evaluated. This study can be used as a reference CO2 pre-pad energized fracturing of shale oil reservoirs in the Ordos basin.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129335994","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 Approach of Petrophysical Rock Typing (PRT) for Carbonate Reservoir Using KNN Based on Conventional Wireline Data and Core Analysis Data","authors":"X. Nie, An Wang, Jianfei Hao","doi":"10.2118/214200-ms","DOIUrl":"https://doi.org/10.2118/214200-ms","url":null,"abstract":"\u0000 For reservoir simulation, one of the most important part of reservoir characterization is rock typing, where rock quality is evaluated and estimated for any simulation grid and OOIP (original oil in place) is calculated based on average petrophysical parameters for any layer. To allocate different rock types to simulation grids, rock types should be assigned according to ranges of parameters that differentiate different rock types.\u0000 Based on the experience in carbonate reservoirs of XXXX oilfield and other oilfields, irreducible water saturation (Swi) is a critical differentiation parameter for rock typing, although it can be difficult and expensive to evaluate. In oil zones, water saturation from log data is assumed to be the irreducible water saturation. The problem arises in transition zone and water zone, where water saturation from log data is not equal to the irreducible water saturation of that rock.\u0000 KNN(K-Nearest Neighbor) is an effective machine learning method for classification and regression in many industries including geo-science. Models can be trained and predict irreducible water saturation from the traditional logs such as GR, Density, Neutron, Sonic using KNN and other Machine Learning methods using labelled data from oil zones. Randomly selected 50% of the dataset was used for training and other 50% was used as testing dataset to be predicted. The prediction precision of KNN method can reach the minimum 92% line for all 25 wells studied and is most robust compared to other methods such as Random Forest and SVM. The trained model was used to predict all the rock types in the reservoir and was confirmed in wells with core data and other advanced measurements data.\u0000 A new approach of petrophysical rock typing (PRT) for carbonate reservoir using KNN based on traditional wireline data and core analysis data is studied and the results show it can solve the PRT problems in carbonate reservoir simulation without acquiring extra data and additional cost. A new workflow was established to process wireline data and provide the PRT results based on wireline data for every newly drilled well on top of traditional \"Porosity-Permeability-Saturation\" petrophysical evaluation results. This paper presents the methodology, workflow, results, verification, as well as appropriate application scenarios of this new approach. Considering the requirements of the data input and the workflow of the approach, it could be applied widely in similar carbonate reservoirs.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"67 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126305988","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":"Experimental Study on the Effects if Ift Reduction on Water Blockage after Hydraulic Fracturing in Tight Sandstone Reservoirs Based on The NMR Method","authors":"Xiaoyu Hou, J. Sheng, Jiacheng Dai","doi":"10.2118/214189-ms","DOIUrl":"https://doi.org/10.2118/214189-ms","url":null,"abstract":"\u0000 The current studies regarding the effect of interfacial tension (IFT) reduction on removing the water blockage of tight sandstones are significant, but the migration characteristics of trapped water in the stimulation process have not been researched. These issues lead to the stimulation mechanism of IFT reduction after hydraulic fracturing is unclear. In this work, a new coreflood platform was designed to simulate the water invasion, shut-in, and flowback process, and how the IFT affects the water blockage was further studied from pore levels. The oil production rates before and after shut-in were measured, which were used to detect the regained permeability of tight sandstones. The T2 spectrum signals, 1D frequency, and magnetic resonance imaging (MRI) based on the nuclear magnetic resonance (NMR) experiments were used to explore the migration characteristics of trapped water under different conditions. The results indicate that the core damage induced by water invasion is severe. The regained permeability is decreased to less than 25% after shut-in. IFT reduction is an effective way to improve the regained permeability, but the emulsification effect of fracturing fluid needs to be avoided, which will reduce the permeability of tight sandstones by the Jiamin effect. The NMR signals of the 1D profile show the water saturation of cores gradually decreases from the fracture face to the exit end, which demonstrates that the water blockage occurs mainly in the area near the fracture face. The T2 spectrum signals show that the residual water saturation of mesopores and macropores after flowback can be reduced by decreasing the IFT values, but the reduction of residual water saturation in micropores is insignificant. This result demonstrates that the core damage caused by water blockage may mainly come from mesopores and micropores. Our study reveals a deeper mechanism of removing water blockage during the IFT reduction process, which can guide the application of surfactants in the oil field.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"96 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134119015","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Innovative Integrated Workflow to Reduce Uncertainties and Improve Hydrocarbon Recovery","authors":"Y. Boudiba, Maneesh Pisharat, Mohamed Kelkouli, Ferhat Nettari, Nordin Meddour, Bilal Seddar, Reda Adam Babbouchi, Abdelhakim Berbra","doi":"10.2118/214136-ms","DOIUrl":"https://doi.org/10.2118/214136-ms","url":null,"abstract":"\u0000 In producing fields, re-mapping reservoir fluid content and new contacts are one of the most important objectives in pursuit of optimized well productivity. Wireline logs and formation testing (FT) data is widely used for this purpose. Continuous fluid data from Advanced Mud Gas (AMG) analysis with downhole logs can be used to generate a comprehensive dataset for reservoir evaluation. Each method has its limitations and advantages. Combining and interpreting the output from the fundamentally different datasets require an experienced petro-technical expert with a specific skill set.\u0000 To calculate hydrocarbon volume, estimate and forecast reserves, formation fluid evaluation has primarily relied on traditional methods that depends heavily on formation pressure measurements. This was achieved through the analysis of gradients and local fluid contacts. This approach can be misleading for brownfields, where a sizable amount of producible hydrocarbon is left in the reservoir.\u0000 For characterizing formation fluid, a novel approach utilizing complimentary technologies was adopted. For early hydrocarbon detection and FT program optimization, AMG data was first gathered while drilling. Post drilling open Hole logs, formation pressure and fluid data were acquired not only to verify the AMG findings but also to fill in the gaps regarding water-swept zones, reservoir pressure and depletion, exact fluid contacts, and fluid characteristics to reduce uncertainties.\u0000 During the job execution, AMG data was effectively used to provide early formation fluid identification and contacts. This information was used to optimize the wireline advanced fluid analysis stations. AMG analysis identified multiple fluids (wet gas, gas condensate, oil, and water) and revealed a much greater complexity of the reservoir than initially expected, which could not have been achieved with standard formation evaluation or other fluid contact identification techniques based on regional gradient analysis. The fluid types and contacts identified by AMG were then confirmed by the wireline downhole fluid analysis. Using this workflow, a high potential recoverable hydrocarbon oil was identified over a reservoir that was classified as a water zone based on initial evaluation and knowledge.\u0000 In this field, an innovative method was adopted for reservoir fluid characterization. This approach based on digital integration and a unified workflow was used successfully for fluid contact identification, targeted fluid sampling, and identifying and recovering more hydrocarbon from the swept zones.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"18 4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133356845","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":"Surfactant Selection for Foam Generation: Implications for CO2 Geo-Sequestration","authors":"K. Kirtivardhan, A. Kakati","doi":"10.2118/214231-ms","DOIUrl":"https://doi.org/10.2118/214231-ms","url":null,"abstract":"\u0000 The storage of CO2 foam in saline aquifers is an effective way of CO2 geo-sequestration. However, one of the primary concerns during storage of CO2 in underground geological reservoirs is the rapid upward migration of CO2 plume which eventually challenges the containment security. Injection of foam has been proposed as an effective solution to this problem from decades. Foams have low mobility and prevent the formation of high mobility channels. Surfactant is a crucial component in generating stable aqueous foam. The selection of surfactants as foaming agents is very important for the performance of the foam. The stability of a surfactant generated foam depends on the surfactant type, its concentration, salinity, pressure and temperature. In this study, stability of foam generated with two surfactants sodium dodecylbenzenesulphonate (anionic) and cetyl trimethylammonium bromide (cationic) are investigated at different surfactant concentrations. The effect of salinity and temperature were also investigated. The form was generated by purging air into a brine solution containing the surfactant. The foamability and the stability of the produced foam is first observed under room temperature and are then observed under elevated temperatures. The elevated temperature foam stability is observed by keeping the produced foam in an oven. The foamability was observed to increase with surfactant concentration. The salt inhibits generation of foam and the effect is prominent for CTAB than SDBS. The CTAB assisted foam has a higher stability than SDBS. However, at high temperature the foam stability was found to reduce significantly for both SDBS and CTAB; with CTAB foam has slightly higher stability than SDBS.","PeriodicalId":349960,"journal":{"name":"Day 2 Tue, March 14, 2023","volume":"266 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116451755","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}