Advancements in pore-scale and core-scale studies have provided an improved understanding of the micro- and macro-porosity nature of carbonate rocks and how the two systems interact. The interaction of the two systems in the presence of a third (fracture) and fourth component (vugs) has not been fully investigated in the industry. This paper demonstrates applicability and some limitations of permeability conditioning practices in dual-porosity dual-permeability (DPDP) systems. In addition, this work demonstrates how the permeability conditioning process can be used as a tool for dynamic classification and calibration of extreme permeability (super-k) intervals in dual-permeability systems. A highly scalable parallel DPDP finite difference simulator is used to: Firstly, demonstrate the permeability conditioning process and how it impacts reservoir dynamics. Secondly, present cases where flowmeter (PLT) responses show a limitation in characterizing super-k intervals and its impact. Thirdly, demonstrate the role of enhancement factor in representing flood front movement for multiple super-k dominated reservoir realizations constrained by flowmeter and pressure transient permeability-thickness controls. The results of this work expands on the representation of super-k intervals in dual-permeability systems in three main areas. Firstly, the decision to explicitly model super-k intervals as a fractured media or to implicitly model these features as a matrix permeability enhancement should be evaluated with use of enhancement factor combined with water breakthrough trends observed in the field. Secondly, the use of PLT responses to characterize super-k intervals should be made after careful evaluation of their responses before and after any well intervention. This step is crucial for proper permeability conditioning and in capturing reservoir dynamics of masked high flow intervals, i.e., new flow dominating features that appear only after the original super-k intervals have been plugged. Thirdly, as part of the integration of pressure transient results into a DPDP finite difference model, special consideration is needed for wells with a non-intersecting conductive fracture signature due to a limitation in the Peaceman formulation for DPDP reservoirs, which only considers cells intersecting the well for productivity index and PLT response calculations. In summary, this paper provides guidance for geologists and reservoir engineers, through use of a permeability conditioning process, to dynamically classify and calibrate fractured/super-k intervals during the process of constructing full-field dual-porosity dual-permeability reservoir simulation models.
{"title":"Dynamic Data Integration in Dual-Porosity Dual-Permeability Reservoirs: Permeability Conditioning Perspective","authors":"A. Alramadhan, S. Lyngra","doi":"10.2118/200258-ms","DOIUrl":"https://doi.org/10.2118/200258-ms","url":null,"abstract":"\u0000 Advancements in pore-scale and core-scale studies have provided an improved understanding of the micro- and macro-porosity nature of carbonate rocks and how the two systems interact. The interaction of the two systems in the presence of a third (fracture) and fourth component (vugs) has not been fully investigated in the industry. This paper demonstrates applicability and some limitations of permeability conditioning practices in dual-porosity dual-permeability (DPDP) systems. In addition, this work demonstrates how the permeability conditioning process can be used as a tool for dynamic classification and calibration of extreme permeability (super-k) intervals in dual-permeability systems.\u0000 A highly scalable parallel DPDP finite difference simulator is used to: Firstly, demonstrate the permeability conditioning process and how it impacts reservoir dynamics. Secondly, present cases where flowmeter (PLT) responses show a limitation in characterizing super-k intervals and its impact. Thirdly, demonstrate the role of enhancement factor in representing flood front movement for multiple super-k dominated reservoir realizations constrained by flowmeter and pressure transient permeability-thickness controls.\u0000 The results of this work expands on the representation of super-k intervals in dual-permeability systems in three main areas. Firstly, the decision to explicitly model super-k intervals as a fractured media or to implicitly model these features as a matrix permeability enhancement should be evaluated with use of enhancement factor combined with water breakthrough trends observed in the field. Secondly, the use of PLT responses to characterize super-k intervals should be made after careful evaluation of their responses before and after any well intervention. This step is crucial for proper permeability conditioning and in capturing reservoir dynamics of masked high flow intervals, i.e., new flow dominating features that appear only after the original super-k intervals have been plugged. Thirdly, as part of the integration of pressure transient results into a DPDP finite difference model, special consideration is needed for wells with a non-intersecting conductive fracture signature due to a limitation in the Peaceman formulation for DPDP reservoirs, which only considers cells intersecting the well for productivity index and PLT response calculations.\u0000 In summary, this paper provides guidance for geologists and reservoir engineers, through use of a permeability conditioning process, to dynamically classify and calibrate fractured/super-k intervals during the process of constructing full-field dual-porosity dual-permeability reservoir simulation models.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88022396","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}
D. Lagomarsino, Matteo Fornari, C. Barbieri, T. Ciccarone, Alessandro Lomartire, E. Norelli, D. Rosa
The exploiting of High Resolution (HR) Pre Stack Depth Migration (PSDM) 3D seismic volumes, normally used for Oil & Gas exploration, has been pushed forward in geomorphological and geohazard risk evaluation. The novel approach proposed here allows to carry out such activities very early in respect of the standard work flow. Early awareness of critical areas turns out to be crucial in fast-tracking projects and allows a design to cost optimization. The 3D HR PSDM outputs are processed in order to generate a detailed imaging of the shallower portion of the seismic volumes. The volumes are processed at a 2 meters depth interval and converted in time (DTT). Finally, a dedicated post migration time processing sequence, followed by time-to-depth conversion, is applied to generate a Higher Resolution Volume (HRV) in depth domain. The resulting 3D volume is then analyzed to study the seabed and the sub-bottom from a geomorphological standpoint. The analyses focus on the identification and mapping of the distribution of the "areas of instability" eventually classified according to a specific KPI (Safety Factor Index in static conditions), providing a quantitative slope stability assessment of the area. The new approach has been validated comparing the DTM (Digital Topographic Model) derived from the 3D HR PSDM volume and the available MBES (Multi Beam Echo Sounder) bathymetry. The proposed approach leads to a dramatic improvement in the detection capability, highlighting the major critical structures such as: canyon flanks, buried slides, creeps and tension cracks on the shelf break, boulders and compacted sediments, sediment banks and sediment waves reshaped by bottom currents, pockmark areas and fluid escapes, turbidity mass movements and furrows due to tectonic activities. The approach matches perfectly the detection capability of a traditional MBES approach. The described workflow is potentially highly beneficial for early de-risking assets and operations, especially for facilities installation. The proposed innovative approach allows a detailed planning of dedicated data acquisition campaigns, restricted to the most critical areas, with a tangible reduction in the turnaround times and cost savings crucial for project economics.
{"title":"Leveraging 3D High Resolution PSDM Data Volumes for Early Geohazard Detection","authors":"D. Lagomarsino, Matteo Fornari, C. Barbieri, T. Ciccarone, Alessandro Lomartire, E. Norelli, D. Rosa","doi":"10.2118/200062-ms","DOIUrl":"https://doi.org/10.2118/200062-ms","url":null,"abstract":"\u0000 The exploiting of High Resolution (HR) Pre Stack Depth Migration (PSDM) 3D seismic volumes, normally used for Oil & Gas exploration, has been pushed forward in geomorphological and geohazard risk evaluation. The novel approach proposed here allows to carry out such activities very early in respect of the standard work flow. Early awareness of critical areas turns out to be crucial in fast-tracking projects and allows a design to cost optimization.\u0000 The 3D HR PSDM outputs are processed in order to generate a detailed imaging of the shallower portion of the seismic volumes. The volumes are processed at a 2 meters depth interval and converted in time (DTT). Finally, a dedicated post migration time processing sequence, followed by time-to-depth conversion, is applied to generate a Higher Resolution Volume (HRV) in depth domain. The resulting 3D volume is then analyzed to study the seabed and the sub-bottom from a geomorphological standpoint. The analyses focus on the identification and mapping of the distribution of the \"areas of instability\" eventually classified according to a specific KPI (Safety Factor Index in static conditions), providing a quantitative slope stability assessment of the area.\u0000 The new approach has been validated comparing the DTM (Digital Topographic Model) derived from the 3D HR PSDM volume and the available MBES (Multi Beam Echo Sounder) bathymetry.\u0000 The proposed approach leads to a dramatic improvement in the detection capability, highlighting the major critical structures such as: canyon flanks, buried slides, creeps and tension cracks on the shelf break, boulders and compacted sediments, sediment banks and sediment waves reshaped by bottom currents, pockmark areas and fluid escapes, turbidity mass movements and furrows due to tectonic activities. The approach matches perfectly the detection capability of a traditional MBES approach.\u0000 The described workflow is potentially highly beneficial for early de-risking assets and operations, especially for facilities installation. The proposed innovative approach allows a detailed planning of dedicated data acquisition campaigns, restricted to the most critical areas, with a tangible reduction in the turnaround times and cost savings crucial for project economics.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89069492","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}
Duraid Al-Bayati, A. Saeedi, Ipek Ktao, M. Myers, C. White, A. Mousavi, Q. Xie, C. Lagat
Reservoir heterogeneity reflected by permeability variation in the vertical direction is expected to significantly impact on the subsurface multiphase flow behaviour. In this context, we have shown previously that during immiscible flooding the crossflow between low and high permeability zones plays a significant role in determining the reservoir performance in terms of the hydrocarbon yield. In this manuscript, the contribution of crossflow to oil recovery in layered sandstone porous media during miscible CO2 flooding is explored. We conducted core flooding experiments using a core sample constructed by attaching two axially split half sandstone plugs each with a different permeability (0.008 and 0.1 (μm)2). The crossflow between the two layers was controlled by placing either a lint-free tissue paper or an impermeable Teflon sheet to represent a layered heterogeneity with and without communication, respectively. Additionally, to better understand the underpinning mechanisms influencing the flood performance, we imaged the samples during flooding using a high-resolution medical X-Ray computed tomography (XCT) scanner. Our results show that core-scale heterogeneity would indeed play an important role in determining the spatial distribution of the injected CO2during miscible flooding, consequently the oil recovery factor. For instance, our results confirm that permeability heterogeneity in vertical direction would lead to CO2 establishing a prefrential flow path through the high permeability layer leading to its early breakthrough. The above-mentioned CO2 channeling is clearly evident from the X-ray images captured during flooding. However, a reasonble amount of CO2 would still enter the low permeability layer contributing positively to the ultimate oil recovery factor. In fact, the post-processing of the XCT data confirmed the above to take place when cross-layer communication was allowed. The diversion of CO2 from the high to low permeablity layer is believed to be due to the crossflow phenomenon (induced by the viscous and dispersion forces) resulting in a subtle increase (i.e. 1.7%) in the ultimate oil recovery. In a similar study we have done about immiscible flooding, the contribution of crossflow to the overall recovery was found to be about 5%. The less pronounced effect of crossflow under miscible conditions is believed to be due to the absence of capillarity as a more effective driving force behind crossflow. To the best of our knowledge, our core-flooding results as presented in this manuscript and backed by X-ray CT visualisation, are the first set of their kind. They are insightful and would be of interest to the scientific community in revealing how crossflow may control flow behaviour in heterogeneous sandstone reservoirs, with important implications for numerical modelling of CO2 injection.
{"title":"X-Ray Computed Tomography Assisted Investigation of Flow Behaviour of Miscible CO2 to Enhance Oil Recovery in Layered Sandstone Porous Media","authors":"Duraid Al-Bayati, A. Saeedi, Ipek Ktao, M. Myers, C. White, A. Mousavi, Q. Xie, C. Lagat","doi":"10.2118/200103-ms","DOIUrl":"https://doi.org/10.2118/200103-ms","url":null,"abstract":"\u0000 Reservoir heterogeneity reflected by permeability variation in the vertical direction is expected to significantly impact on the subsurface multiphase flow behaviour. In this context, we have shown previously that during immiscible flooding the crossflow between low and high permeability zones plays a significant role in determining the reservoir performance in terms of the hydrocarbon yield. In this manuscript, the contribution of crossflow to oil recovery in layered sandstone porous media during miscible CO2 flooding is explored. We conducted core flooding experiments using a core sample constructed by attaching two axially split half sandstone plugs each with a different permeability (0.008 and 0.1 (μm)2). The crossflow between the two layers was controlled by placing either a lint-free tissue paper or an impermeable Teflon sheet to represent a layered heterogeneity with and without communication, respectively. Additionally, to better understand the underpinning mechanisms influencing the flood performance, we imaged the samples during flooding using a high-resolution medical X-Ray computed tomography (XCT) scanner.\u0000 Our results show that core-scale heterogeneity would indeed play an important role in determining the spatial distribution of the injected CO2during miscible flooding, consequently the oil recovery factor. For instance, our results confirm that permeability heterogeneity in vertical direction would lead to CO2 establishing a prefrential flow path through the high permeability layer leading to its early breakthrough. The above-mentioned CO2 channeling is clearly evident from the X-ray images captured during flooding. However, a reasonble amount of CO2 would still enter the low permeability layer contributing positively to the ultimate oil recovery factor. In fact, the post-processing of the XCT data confirmed the above to take place when cross-layer communication was allowed. The diversion of CO2 from the high to low permeablity layer is believed to be due to the crossflow phenomenon (induced by the viscous and dispersion forces) resulting in a subtle increase (i.e. 1.7%) in the ultimate oil recovery. In a similar study we have done about immiscible flooding, the contribution of crossflow to the overall recovery was found to be about 5%. The less pronounced effect of crossflow under miscible conditions is believed to be due to the absence of capillarity as a more effective driving force behind crossflow. To the best of our knowledge, our core-flooding results as presented in this manuscript and backed by X-ray CT visualisation, are the first set of their kind. They are insightful and would be of interest to the scientific community in revealing how crossflow may control flow behaviour in heterogeneous sandstone reservoirs, with important implications for numerical modelling of CO2 injection.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80533253","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}
Ibtisam Al-Shabibi, J. Naser, R. Al-Maamari, M. Karimi, A. Al-Salmi, Hajir Al-Qassabi
Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability. This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments. The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.
{"title":"Water Injectivity Decline in an Omani Oil Field: Possible Causes and Mitigation","authors":"Ibtisam Al-Shabibi, J. Naser, R. Al-Maamari, M. Karimi, A. Al-Salmi, Hajir Al-Qassabi","doi":"10.2118/200225-ms","DOIUrl":"https://doi.org/10.2118/200225-ms","url":null,"abstract":"\u0000 Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability.\u0000 This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments.\u0000 The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83428817","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}
Inflow control device (ICD) technology helps in balancing the production across the entire interval, addressing some of the challenges associated with horizontal and deviated wells. Nevertheless, ICDs have limited capabilities in identifying and restricting unwanted fluids upon breakthrough. Autonomous ICD (AICD) technology functions similar to an ICD initially (i.e., balancing flux across the length of horizontal wells, effectively delaying breakthrough) but has the additional benefit of restricting the flow of unwanted fluids upon breakthrough. Multiple AICD case histories highlighting the benefit of the technology in mitigating well performance challenges and delivering improved recovery throughout the life of the well are discussed. AICD technology is fluid dependent, principally reacting to the properties of the fluid flowing through it and creating an additional pressure drop to restrict the production of unwanted fluids. The fluidic diode-type AICD has no moving parts and uses flow dynamic properties to distinguish between the fluids. It uses downhole fluid properties to accurately differentiate between oil, water, and gas; and changes the flow path autonomously to restrict unwanted fluids upon breakthrough; and uplifts oil production from the oil-saturated zones across the wellbore. Extensive testing has been completed to characterize and accurately predict the flow performance, which enables designing an AICD completion efficiently. Flow performance analysis of the various types of fluidic diode AICDs designed to address various well performance challenges [i.e., high gas-oil ratio (GOR) or high water production or both, increasing oil production] is discussed. The flow performance analysis has been derived using extensive and rigorous single-phase and multiphase flow-loop test programs, covering the wide range of oil properties. This paper will also highlight the screening criteria in selecting a candidate well for fluidic diode AICDs application. Furthermore, the paper will also discuss in detail a reservoir-focused well-centric completion design workflow for designing fluidic diode-type AICD completions for a candidate well. This collaborative workflow takes into account the various subsurface and well attributes to meet or exceed well key performance indicators (KPIs) over the life of the well. It can be observed from the results of various field installations and production data analysis that installing AICDs during the early life of wells or fields results in a higher ultimate recovery (UR) compared to installing it in brown or matured fields. However, the recovery with AICD in brown/matured fields can be higher than ICD or any other legacy openhole completion. The fluidic diode AICD design methodology and field installation results for AICD technology in different completion designs, such as openhole gravel pack, open hole, retrofit, artificial lift completion, and multilateral wells, are discussed as well. Additionally, it
{"title":"Fluidic Diode Autonomous ICD Selection Criteria, Design Methodology, and Performance Analysis for Multiple Completion Designs: Case Studies","authors":"Tejas Kalyani, G. Corona, Kevin Ross","doi":"10.2118/200255-ms","DOIUrl":"https://doi.org/10.2118/200255-ms","url":null,"abstract":"\u0000 Inflow control device (ICD) technology helps in balancing the production across the entire interval, addressing some of the challenges associated with horizontal and deviated wells. Nevertheless, ICDs have limited capabilities in identifying and restricting unwanted fluids upon breakthrough. Autonomous ICD (AICD) technology functions similar to an ICD initially (i.e., balancing flux across the length of horizontal wells, effectively delaying breakthrough) but has the additional benefit of restricting the flow of unwanted fluids upon breakthrough. Multiple AICD case histories highlighting the benefit of the technology in mitigating well performance challenges and delivering improved recovery throughout the life of the well are discussed.\u0000 AICD technology is fluid dependent, principally reacting to the properties of the fluid flowing through it and creating an additional pressure drop to restrict the production of unwanted fluids. The fluidic diode-type AICD has no moving parts and uses flow dynamic properties to distinguish between the fluids. It uses downhole fluid properties to accurately differentiate between oil, water, and gas; and changes the flow path autonomously to restrict unwanted fluids upon breakthrough; and uplifts oil production from the oil-saturated zones across the wellbore.\u0000 Extensive testing has been completed to characterize and accurately predict the flow performance, which enables designing an AICD completion efficiently. Flow performance analysis of the various types of fluidic diode AICDs designed to address various well performance challenges [i.e., high gas-oil ratio (GOR) or high water production or both, increasing oil production] is discussed. The flow performance analysis has been derived using extensive and rigorous single-phase and multiphase flow-loop test programs, covering the wide range of oil properties.\u0000 This paper will also highlight the screening criteria in selecting a candidate well for fluidic diode AICDs application. Furthermore, the paper will also discuss in detail a reservoir-focused well-centric completion design workflow for designing fluidic diode-type AICD completions for a candidate well. This collaborative workflow takes into account the various subsurface and well attributes to meet or exceed well key performance indicators (KPIs) over the life of the well.\u0000 It can be observed from the results of various field installations and production data analysis that installing AICDs during the early life of wells or fields results in a higher ultimate recovery (UR) compared to installing it in brown or matured fields. However, the recovery with AICD in brown/matured fields can be higher than ICD or any other legacy openhole completion.\u0000 The fluidic diode AICD design methodology and field installation results for AICD technology in different completion designs, such as openhole gravel pack, open hole, retrofit, artificial lift completion, and multilateral wells, are discussed as well. Additionally, it","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80896906","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}
Conny Velazco-Quesada, Luis Vargas, M. Sawafi, A. Busaidi, Hilal Mamari, A. Yahyai, K. Woolsey, B. Montilla
A field trial has been completed in five oil producing wells, completed with progressive cavity pump (PCP) and under sand co-production scheme with the following objectives: Increasing well uptime by eliminating rotor stuck events and extending time between failures,Reducing locked-in potential associated to slow ramp-up process from initial to target offtake,Reducing the need for operator visits to start or adjust well running conditions after station trips, To achieve this, four wells with very premature failures (less than 6-months) were selected for the trial. One fifth well with high level of depletion was also selected. The target for this last application was to check the impact of reducing fluid level safety factor on pump performance. In all wells, PCP well controllers were installed with self-optimization routines that maintained safe fluid levels above the pump intake while adjusting speed for potential sand ingress. Speed ramp-up time was programmed for completion within two days of start up. First, realtime signals were enhanced to monitor all well parameters that could affect performance, such as tubing head pressure (THP) and casing head pressure (CHP). This information was key to manage the actual fluid levels above the pump, even in gassy wells, allowing safety factors to be reduced by 50% without affecting pump performance. Increase in pump run life by 40 to 140% was observed in the four sandy wells selected. No well interventions were required for sand flushing. Ramp-up time was successfully completed within a day of start-up and after two days production at target was stabilized. After trips, it was found that the well started without the need for operators, as long as power supply was restored. Operator visits were only required for power or signal issues to be fixed, but well was safely kept optimized within those periods. Estimated oil production availability increase from this trial is 12% per well per year. This paper presents the main learnings from applying a self-optimization routine in 5 sandy wells and what is important to consider to achieve cost reduction, increase in well uptime and to reduce the need for manual adjustments/field visits.
{"title":"Improving Uptime of Sandy Wells with PCPs Through the Application of Self-Optimization Routines","authors":"Conny Velazco-Quesada, Luis Vargas, M. Sawafi, A. Busaidi, Hilal Mamari, A. Yahyai, K. Woolsey, B. Montilla","doi":"10.2118/200211-ms","DOIUrl":"https://doi.org/10.2118/200211-ms","url":null,"abstract":"\u0000 A field trial has been completed in five oil producing wells, completed with progressive cavity pump (PCP) and under sand co-production scheme with the following objectives: Increasing well uptime by eliminating rotor stuck events and extending time between failures,Reducing locked-in potential associated to slow ramp-up process from initial to target offtake,Reducing the need for operator visits to start or adjust well running conditions after station trips,\u0000 To achieve this, four wells with very premature failures (less than 6-months) were selected for the trial. One fifth well with high level of depletion was also selected. The target for this last application was to check the impact of reducing fluid level safety factor on pump performance.\u0000 In all wells, PCP well controllers were installed with self-optimization routines that maintained safe fluid levels above the pump intake while adjusting speed for potential sand ingress. Speed ramp-up time was programmed for completion within two days of start up.\u0000 First, realtime signals were enhanced to monitor all well parameters that could affect performance, such as tubing head pressure (THP) and casing head pressure (CHP). This information was key to manage the actual fluid levels above the pump, even in gassy wells, allowing safety factors to be reduced by 50% without affecting pump performance.\u0000 Increase in pump run life by 40 to 140% was observed in the four sandy wells selected. No well interventions were required for sand flushing. Ramp-up time was successfully completed within a day of start-up and after two days production at target was stabilized.\u0000 After trips, it was found that the well started without the need for operators, as long as power supply was restored. Operator visits were only required for power or signal issues to be fixed, but well was safely kept optimized within those periods.\u0000 Estimated oil production availability increase from this trial is 12% per well per year.\u0000 This paper presents the main learnings from applying a self-optimization routine in 5 sandy wells and what is important to consider to achieve cost reduction, increase in well uptime and to reduce the need for manual adjustments/field visits.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84886812","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}
Z. Alyousef, Othman Swaie, A. Alabdulwahab, S. Kokal
The in-situ generation of foam is one of the most promising techniques to solve gas mobility challenges in petroleum reservoirs and subsequently improve the volumetric sweep efficiency. The stabilization of foam at reservoir conditions is a major challenge. The harsh reservoir conditions, such as high temperature, high brine salinity, together with surfactant adsorption on the rock may result in unstable foam and, consequently, poor sweep efficiency. Foam additives, such as polymers, might help strengthen the physical properties of foam film and improve foam stability. This work evaluates the effectiveness of a polymer on enhancing CO2-foam stabilization at harsh reservoir conditions. Static and dynamic foam tests were conducted to evaluate the role of polymer on foam stability. Three foaming surfactants were used to assess the ability of the polymer on enhancing foam stabilization. The static foam tests were conducted at conditions similar to reservoir conditions using test tubes. Foam column, and foam life were measured to evaluate the role of the polymer on foam stabilization. Foam viscosity in absence and presence of the polymer was measured using foam rheometer apparatus. The dynamic foam tests were conducted to assess the ability of tested materials to generate viscous foams and also measure the CO2 mobility in porous media using a coreflooding system. The mobility reduction factor (MRF) was measured at high pressure and high temperature (HPHT) conditions, 3200 psi and 100°C. The static foam tests and foam rheology measurements indicated that the addition of the polymer enhanced foam stability as a result of increasing the bulk viscosity of the aqueous solutions. The results found that the foam life increased with the polymer concentration. However, the increase of polymer concentration makes the solution very viscous, hence, the foam generation becomes challenging. The dynamic foam tests showed that the foam generated in absence of the polymer was able to reduce the CO2 mobility 13 fold. However, the addition of the polymer resulted in higher pressure drops during CO2 floods, more resistance to gas flow and, therefore, lower gas mobility compared to that obtained with surfactant alone. The addition of the polymer reduced the CO2 mobility 50 fold. This higher reduction in the CO2 mobility as a result of adding the polymer can be attributed to the effectiveness of the polymer in improving the foam stabilization and prolong the life of generated foam.
{"title":"The Role of Polymer on Surfactant-Foam Stability During Carbon Dioxide Mobility Control Process","authors":"Z. Alyousef, Othman Swaie, A. Alabdulwahab, S. Kokal","doi":"10.2118/200125-ms","DOIUrl":"https://doi.org/10.2118/200125-ms","url":null,"abstract":"\u0000 The in-situ generation of foam is one of the most promising techniques to solve gas mobility challenges in petroleum reservoirs and subsequently improve the volumetric sweep efficiency. The stabilization of foam at reservoir conditions is a major challenge. The harsh reservoir conditions, such as high temperature, high brine salinity, together with surfactant adsorption on the rock may result in unstable foam and, consequently, poor sweep efficiency. Foam additives, such as polymers, might help strengthen the physical properties of foam film and improve foam stability. This work evaluates the effectiveness of a polymer on enhancing CO2-foam stabilization at harsh reservoir conditions.\u0000 Static and dynamic foam tests were conducted to evaluate the role of polymer on foam stability. Three foaming surfactants were used to assess the ability of the polymer on enhancing foam stabilization. The static foam tests were conducted at conditions similar to reservoir conditions using test tubes. Foam column, and foam life were measured to evaluate the role of the polymer on foam stabilization. Foam viscosity in absence and presence of the polymer was measured using foam rheometer apparatus. The dynamic foam tests were conducted to assess the ability of tested materials to generate viscous foams and also measure the CO2 mobility in porous media using a coreflooding system. The mobility reduction factor (MRF) was measured at high pressure and high temperature (HPHT) conditions, 3200 psi and 100°C.\u0000 The static foam tests and foam rheology measurements indicated that the addition of the polymer enhanced foam stability as a result of increasing the bulk viscosity of the aqueous solutions. The results found that the foam life increased with the polymer concentration. However, the increase of polymer concentration makes the solution very viscous, hence, the foam generation becomes challenging. The dynamic foam tests showed that the foam generated in absence of the polymer was able to reduce the CO2 mobility 13 fold. However, the addition of the polymer resulted in higher pressure drops during CO2 floods, more resistance to gas flow and, therefore, lower gas mobility compared to that obtained with surfactant alone. The addition of the polymer reduced the CO2 mobility 50 fold. This higher reduction in the CO2 mobility as a result of adding the polymer can be attributed to the effectiveness of the polymer in improving the foam stabilization and prolong the life of generated foam.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85274204","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}
Polymer flood (PF) applications have increasingly been extended to medium-to-heavy oil reservoirs for enhanced displacement and sweep efficiency and pushing the recovery beyond the limits of conventional recovery techniques. The relatively low carbon footprint and gas-light nature has made PF attractive in many cases compared to the traditional thermal methods. Consequently, many fields in the Sultanate of Oman with viscosities ranging from about 90cP to 500cP have been studied and field trialled for polymer development, and one such field has been successfully undergoing field-scale PF for over 8 years, which is the subject of this study. As PF is matured in the field, the ongoing challenge is to support production operations and optimise flood performance. This study lays the foundation for holistic simulation study targeting theoretical based considerations for PF optimization. It starts with understanding the nature of polymer/polymer and polymer/water type displacements and stabilities, and encompasses modelling the phenomena of viscous fingering/instabilities in a range of model set-ups, starting from high resolution core-scale 2D models to 3D sector models incorporating varying degrees of geological heterogeneities. Understanding of displacement stability gained with high-resolution models is extended to investigate polymer/water mixing, Water-Alternating-Polymer (WAP) recovery and polymer grading (tapering). These subjects have been integrated to emphasise the optimal polymer slug size requirement with creaming curve analyses that build on the principles of containing fingers/instabilities due to lower viscosity follow-up slugs or chase water. The polymer flood optimization is taken to the next step by investigating the concepts of polymer grading. Three prevalent grading concepts proposed by Claridge ([5], [6], [7], [8]), Ligthelm-Schulte and Stegemeier in combination with different mixing rules form the basis of polymer grading assessment. The study highlights significant scope for optimizing polymer flood in the field both in terms of long-term improved recovery performance at reduced cost as well as tackling the short-term operational challenges, potentially impacting the business bottom-line.
{"title":"Optimizing Ongoing Field Scale Polymer Flood in South of Oman Through Detailed Simulation","authors":"A. Anand, O. Riyami","doi":"10.2118/200207-ms","DOIUrl":"https://doi.org/10.2118/200207-ms","url":null,"abstract":"\u0000 Polymer flood (PF) applications have increasingly been extended to medium-to-heavy oil reservoirs for enhanced displacement and sweep efficiency and pushing the recovery beyond the limits of conventional recovery techniques. The relatively low carbon footprint and gas-light nature has made PF attractive in many cases compared to the traditional thermal methods. Consequently, many fields in the Sultanate of Oman with viscosities ranging from about 90cP to 500cP have been studied and field trialled for polymer development, and one such field has been successfully undergoing field-scale PF for over 8 years, which is the subject of this study.\u0000 As PF is matured in the field, the ongoing challenge is to support production operations and optimise flood performance.\u0000 This study lays the foundation for holistic simulation study targeting theoretical based considerations for PF optimization. It starts with understanding the nature of polymer/polymer and polymer/water type displacements and stabilities, and encompasses modelling the phenomena of viscous fingering/instabilities in a range of model set-ups, starting from high resolution core-scale 2D models to 3D sector models incorporating varying degrees of geological heterogeneities.\u0000 Understanding of displacement stability gained with high-resolution models is extended to investigate polymer/water mixing, Water-Alternating-Polymer (WAP) recovery and polymer grading (tapering). These subjects have been integrated to emphasise the optimal polymer slug size requirement with creaming curve analyses that build on the principles of containing fingers/instabilities due to lower viscosity follow-up slugs or chase water.\u0000 The polymer flood optimization is taken to the next step by investigating the concepts of polymer grading. Three prevalent grading concepts proposed by Claridge ([5], [6], [7], [8]), Ligthelm-Schulte and Stegemeier in combination with different mixing rules form the basis of polymer grading assessment.\u0000 The study highlights significant scope for optimizing polymer flood in the field both in terms of long-term improved recovery performance at reduced cost as well as tackling the short-term operational challenges, potentially impacting the business bottom-line.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"13 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79487284","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}
The development Chemical EOR technologies is increasing rapidly due to the massive need of hydrocarbons in the world and because most of the reservoirs have reached tertiary recovery phase. Carbonate reservoir have challenging conditions of high salinity and high temperature that affect the performance of SP flooding. In this paper, we are using a commertial simulator to optimize the design SP flooding in these harsh conditions, and use our previous core-flooding experiment to calibrate our simulation model. The porosity distribution for the model was determined by using the micro-CT imaging which gave the distribution along the core. The permeability was calculated based on the porosity-permeability relationship from the real core data. The real surfactant and polymer properties were measured in the lab in terms of rheology and IFT. History matching of the base case to the real core data was performed using particle swarm optimization machine. The matching parameters were the critical capillary number for de-trapping for both low and high IFT flooding, besides the relative permeability curvature parameter. Many scenarios were investigated after having a match with 2.3 AAE. The polymers used are a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. We did previous study to optimize the core-flooding design for SP flooding in the lab but we faced the problem of inconsistency. Because there are some factors that, we cannot control and keep them constant to compare results, like the core permeability and porosity and their distribution and mineralogy. The combination of surfactant and polymer in one slug gives more recovery than the injecting them individually. ATBS gave higher recovery than TVP. There is no difference in recovery due to changing the surfactants because their IFT is close to each other. The observation is that increasing the slug size will increase the recovery so we recommend using diminishing return economic analyses to determine the slug that gives the highest profit. Injecting SW-SP-SW is the best sequence among the other three sequences, taking the advantage of injecting longer slug of viscous fluid, as the increment due to IFT reduction is minor. The viscosity sensitivity study shows higher recovery with more viscous fluids so the limiting factor will be the economics and the pump capacity. Optimizing the SP flooding design for carbonate reservoirs using simulation with the help of lab experiments results for calibration will decrease the uncertainty. This technique is better because you can control the fixed and variable parameters to know exactly the effect of individual ones.
{"title":"Optimization of Sp Flooding Design Using Simulation Calibrated with Lab Core Flooding","authors":"M. Ahmed, A. Sultan","doi":"10.2118/200228-ms","DOIUrl":"https://doi.org/10.2118/200228-ms","url":null,"abstract":"\u0000 The development Chemical EOR technologies is increasing rapidly due to the massive need of hydrocarbons in the world and because most of the reservoirs have reached tertiary recovery phase. Carbonate reservoir have challenging conditions of high salinity and high temperature that affect the performance of SP flooding. In this paper, we are using a commertial simulator to optimize the design SP flooding in these harsh conditions, and use our previous core-flooding experiment to calibrate our simulation model.\u0000 The porosity distribution for the model was determined by using the micro-CT imaging which gave the distribution along the core. The permeability was calculated based on the porosity-permeability relationship from the real core data. The real surfactant and polymer properties were measured in the lab in terms of rheology and IFT. History matching of the base case to the real core data was performed using particle swarm optimization machine. The matching parameters were the critical capillary number for de-trapping for both low and high IFT flooding, besides the relative permeability curvature parameter. Many scenarios were investigated after having a match with 2.3 AAE.\u0000 The polymers used are a Thermo-Viscosifying Polymer (TVP) and an Acrylamido Tertiary Butyl Sulfonate (ATBS)/acrylamide (AM) copolymer. The surfactants are carboxybetaine based amphoteric surfactants SS-880 and SS-885. We did previous study to optimize the core-flooding design for SP flooding in the lab but we faced the problem of inconsistency. Because there are some factors that, we cannot control and keep them constant to compare results, like the core permeability and porosity and their distribution and mineralogy. The combination of surfactant and polymer in one slug gives more recovery than the injecting them individually. ATBS gave higher recovery than TVP. There is no difference in recovery due to changing the surfactants because their IFT is close to each other. The observation is that increasing the slug size will increase the recovery so we recommend using diminishing return economic analyses to determine the slug that gives the highest profit. Injecting SW-SP-SW is the best sequence among the other three sequences, taking the advantage of injecting longer slug of viscous fluid, as the increment due to IFT reduction is minor. The viscosity sensitivity study shows higher recovery with more viscous fluids so the limiting factor will be the economics and the pump capacity.\u0000 Optimizing the SP flooding design for carbonate reservoirs using simulation with the help of lab experiments results for calibration will decrease the uncertainty. This technique is better because you can control the fixed and variable parameters to know exactly the effect of individual ones.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78852597","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}
Injection of foams can be used to optimize different gas injection processes such as CCUS (Carbon Capture Use & Storage) and possibly to boost oil recovery kinetics in heterogenous or naturally fractured reservoirs (Enick R.M. 2012). In this case, foams, which are more viscous and dense than gases, aim at limiting early gas breakthrough during field operation by improving the sweeping efficiency of reservoirs and by blocking the most permeable areas of the latters (A. Al Sumaiti 2017, Chabert M. and D'Souza D. 2016). A large part of the world oil reservoirs that have already been operated by primary and secondary recovery methods are carbonate reservoirs and are mostly located in the Middle East (Talebian S.H. 2014). In these reservoirs, which are often operated by CO2 injection, the adsorption of surfactants on positively charged carbonates may be a major hindrance to foam injection (Pownall 1989, Cui L. and Ma K. 2014). That is why, cationic surfactants have been developed for these CO2 foam applications (Chen Y. 2016). However, these cationics are often hardly soluble at pH>6 (Jian G. 2019) and/or not industrially avalaible (Cui et Dubos 2018). For this study, we selected three different cationic surfactants. Using automated robotic platforms, we explored a large range of surfactant combination (combining each cationic surfactant with a whole co-surfactant portfolio) at high temperature and in a hard concentrated brine (120g/LTDS, [Ca2+]= 8100ppm). We show that adding co-surfactants to each of these cationics boosts their foaming properties in porous media as well as their solubility at high pH (pH=8) while maintaining low levels of adsorption on carbonates. While a high shear rate is required for cationic surfactants to generate foam in sandpacks, formulations combining cationics and co-surfactants form foams at much lower shear rates. Moreover, the fact that these formulations are soluble at pH=8 means that, on field, the water would no longer need to be acidified at the wellhead to solubilize the surfactant blend. Thus, pipe corrosion induced by the flow of acidified solutions in the surface facilities is prevented. Lastly, all the molecules that are tested in this study are industrially available.
注入泡沫可用于优化不同的注气工艺，如CCUS(碳捕获利用与储存)，并可能提高非均质或天然裂缝油藏的采油动力学(Enick R.M. 2012)。在这种情况下，泡沫比气体更粘稠、密度更大，其目的是通过提高储层的清扫效率和堵塞后者最具渗透性的区域，在现场作业中限制早期气体突破(A. Al Sumaiti 2017, Chabert M. and D'Souza D. 2016)。世界上大部分已经采用一次和二次采油方法的油藏都是碳酸盐岩油藏，而且大部分位于中东地区(Talebian S.H. 2014)。在这些油藏中，通常通过注入二氧化碳进行作业，表面活性剂在带正电的碳酸盐上的吸附可能是泡沫注入的主要障碍(Pownall 1989, Cui L. and Ma K. 2014)。这就是为什么阳离子表面活性剂已经被开发用于这些二氧化碳泡沫应用(Chen Y. 2016)。然而，这些阳离子在pH>6时通常难以溶解(Jian G. 2019)和/或无法在工业上使用(Cui et Dubos 2018)。在这项研究中，我们选择了三种不同的阳离子表面活性剂。利用自动化机器人平台，我们在高温和浓硬性盐水(120g/LTDS， [Ca2+]= 8100ppm)中探索了大范围的表面活性剂组合(将每种阳离子表面活性剂与整个助表面活性剂组合在一起)。研究表明，在这些阳离子中加入助表面活性剂可以提高它们在多孔介质中的发泡性能以及在高pH值(pH=8)下的溶解度，同时保持对碳酸盐的低吸附水平。虽然阳离子表面活性剂在沙层中产生泡沫需要很高的剪切速率，但结合阳离子和共表面活性剂的配方可以以更低的剪切速率形成泡沫。此外，这些配方在pH=8时可溶解，这意味着在现场，不再需要在井口酸化水来溶解表面活性剂混合物。因此，防止了由表面设施中酸化溶液流动引起的管道腐蚀。最后，在这项研究中测试的所有分子都是工业上可用的。
{"title":"Co2 Foams in Carbonate Reservoirs at High Temperature: Boosting Cationics Formulation Performances By Additives","authors":"Kerdraon Margaux, Chevallier Eloise, Gland Nicolas, Batot Guillaume","doi":"10.2118/200052-ms","DOIUrl":"https://doi.org/10.2118/200052-ms","url":null,"abstract":"\u0000 Injection of foams can be used to optimize different gas injection processes such as CCUS (Carbon Capture Use & Storage) and possibly to boost oil recovery kinetics in heterogenous or naturally fractured reservoirs (Enick R.M. 2012). In this case, foams, which are more viscous and dense than gases, aim at limiting early gas breakthrough during field operation by improving the sweeping efficiency of reservoirs and by blocking the most permeable areas of the latters (A. Al Sumaiti 2017, Chabert M. and D'Souza D. 2016). A large part of the world oil reservoirs that have already been operated by primary and secondary recovery methods are carbonate reservoirs and are mostly located in the Middle East (Talebian S.H. 2014). In these reservoirs, which are often operated by CO2 injection, the adsorption of surfactants on positively charged carbonates may be a major hindrance to foam injection (Pownall 1989, Cui L. and Ma K. 2014). That is why, cationic surfactants have been developed for these CO2 foam applications (Chen Y. 2016). However, these cationics are often hardly soluble at pH>6 (Jian G. 2019) and/or not industrially avalaible (Cui et Dubos 2018).\u0000 For this study, we selected three different cationic surfactants. Using automated robotic platforms, we explored a large range of surfactant combination (combining each cationic surfactant with a whole co-surfactant portfolio) at high temperature and in a hard concentrated brine (120g/LTDS, [Ca2+]= 8100ppm). We show that adding co-surfactants to each of these cationics boosts their foaming properties in porous media as well as their solubility at high pH (pH=8) while maintaining low levels of adsorption on carbonates. While a high shear rate is required for cationic surfactants to generate foam in sandpacks, formulations combining cationics and co-surfactants form foams at much lower shear rates. Moreover, the fact that these formulations are soluble at pH=8 means that, on field, the water would no longer need to be acidified at the wellhead to solubilize the surfactant blend. Thus, pipe corrosion induced by the flow of acidified solutions in the surface facilities is prevented. Lastly, all the molecules that are tested in this study are industrially available.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"2000 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91548511","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}
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