This paper presents a continuous well performance analysis technique that identifies formation damage and/or productivity loss real-time. It also provides insights into expected damage mechanisms enabling successful and efficient stimulation treatments. The analytical technique recognizes damage patterns at inception. The diagnostics to drive operational decisions are then presented as simple cartesian plots that grant easy access to users of all levels of experience. During initial well ramp-ups, the diagnostic plots can be automated with high frequency data. After reaching target drawdowns, low frequency data provides optimum surveillance. Case studies from several deepwater Gulf of Mexico wells demonstrate how the technique has been successfully operationalized to eliminate productivity loss, gain early insight into damage mechanisms, and investigate the impact of well interventions. Comparisons with pressure transient analysis and numerical history matching studies with all completion details corroborate the robustness of the method. Shutting in the wells is not required for the analysis, therefore lost production and additional stress cycles on the completion are eliminated. The analysis also identifies the maximum drawdown limit, thereby helping the operator optimize well performance real-time.
{"title":"Real-Time Performance Optimization to Prevent Productivity Decline in Deep Offshore Producers","authors":"B. Izgec, L. Kalfayan","doi":"10.2118/208828-ms","DOIUrl":"https://doi.org/10.2118/208828-ms","url":null,"abstract":"\u0000 This paper presents a continuous well performance analysis technique that identifies formation damage and/or productivity loss real-time. It also provides insights into expected damage mechanisms enabling successful and efficient stimulation treatments.\u0000 The analytical technique recognizes damage patterns at inception. The diagnostics to drive operational decisions are then presented as simple cartesian plots that grant easy access to users of all levels of experience. During initial well ramp-ups, the diagnostic plots can be automated with high frequency data. After reaching target drawdowns, low frequency data provides optimum surveillance.\u0000 Case studies from several deepwater Gulf of Mexico wells demonstrate how the technique has been successfully operationalized to eliminate productivity loss, gain early insight into damage mechanisms, and investigate the impact of well interventions. Comparisons with pressure transient analysis and numerical history matching studies with all completion details corroborate the robustness of the method.\u0000 Shutting in the wells is not required for the analysis, therefore lost production and additional stress cycles on the completion are eliminated. The analysis also identifies the maximum drawdown limit, thereby helping the operator optimize well performance real-time.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89825625","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}
Haiyan Zhao, M. Ziauddin, P. Abivin, T. Yusuf, O. Karazincir, Wade Williams, B. Comeaux
Sandstone acidizing operations usually include solvent and acid preflush, main acid treatment, and post-flush stages. However, the acid preflush stage needs good design and execution to prevent formation damage. Moreover, multiple-stage operations require large-volume fluids and pumping time. Therefore, it is challenging to stimulate sandstone formations, especially those with high clay and carbonate content. A novel single-stage acid has been developed to overcome these challenges and improve the stimulation success rate in a cost-effective manner. The application of the new acid system has been studied in laboratory testing. Core flow tests were performed to evaluate the stimulation performance with Berea Gray and Bandera Gray from 160° to 300°F. An inductively coupled plasma (ICP) instrument was used to analyze the ions in the spent acid effluent. The performance was compared with mud acid and organic mud acid. The acid-rock reactions were studied by batch reactor tests. Compatibility with crude oil and mutual solvent was also tested. The results of core flow tests have shown that the new acid was used to treat the sandstone cores effectively at temperatures from 160° to 300°F. The regained permeability range varies from 115% to 400% under different conditions. The new acid provided similar or better performance compared with the combination of acid preflush and mud acid or organic mud acid. High concentrations of Al and Si were observed in the spent acid effluents by ICP analysis, indicating the high dissolution capacity of clays by the new acid. The new acid is highly compatible with carbonate, which was supported by the high concentrations of Ca and Mg in the spent acid. Both core flow tests and batch reactor tests have shown that the new acid stabilizes the problematic ions (Al, Ca, Mg and Fe) in the spent acid. The new acid is compatible with mutual solvent from the core flow tests; therefore, the mutual solvent preflush can be eliminated. The new acid also has good corrosion control due to the relatively high pH compared with mud acid. Overall, the new single stage acid has been used to stimulate the sandstone cores successfully without acid preflush and solvent preflush. A differentiating characteristic of the fluid is that it greatly reduces the risk of treatment failure by reducing primary, secondary, and tertiary precipitation, while maintaining high dissolving power for clays. It uses a different, more cost-effective chemical pathway to stabilize problematic ions compared to traditional single-step sandstone acidizing systems. The new fluid simplifies operation by reducing the total treatment fluid volume, the total number of fluid stages, and the number of fluid types needed at the wellsite.
{"title":"A Novel Single-Stage Sandstone Acidizing Fluid","authors":"Haiyan Zhao, M. Ziauddin, P. Abivin, T. Yusuf, O. Karazincir, Wade Williams, B. Comeaux","doi":"10.2118/208803-ms","DOIUrl":"https://doi.org/10.2118/208803-ms","url":null,"abstract":"\u0000 Sandstone acidizing operations usually include solvent and acid preflush, main acid treatment, and post-flush stages. However, the acid preflush stage needs good design and execution to prevent formation damage. Moreover, multiple-stage operations require large-volume fluids and pumping time. Therefore, it is challenging to stimulate sandstone formations, especially those with high clay and carbonate content. A novel single-stage acid has been developed to overcome these challenges and improve the stimulation success rate in a cost-effective manner.\u0000 The application of the new acid system has been studied in laboratory testing. Core flow tests were performed to evaluate the stimulation performance with Berea Gray and Bandera Gray from 160° to 300°F. An inductively coupled plasma (ICP) instrument was used to analyze the ions in the spent acid effluent. The performance was compared with mud acid and organic mud acid. The acid-rock reactions were studied by batch reactor tests. Compatibility with crude oil and mutual solvent was also tested.\u0000 The results of core flow tests have shown that the new acid was used to treat the sandstone cores effectively at temperatures from 160° to 300°F. The regained permeability range varies from 115% to 400% under different conditions. The new acid provided similar or better performance compared with the combination of acid preflush and mud acid or organic mud acid. High concentrations of Al and Si were observed in the spent acid effluents by ICP analysis, indicating the high dissolution capacity of clays by the new acid. The new acid is highly compatible with carbonate, which was supported by the high concentrations of Ca and Mg in the spent acid. Both core flow tests and batch reactor tests have shown that the new acid stabilizes the problematic ions (Al, Ca, Mg and Fe) in the spent acid. The new acid is compatible with mutual solvent from the core flow tests; therefore, the mutual solvent preflush can be eliminated. The new acid also has good corrosion control due to the relatively high pH compared with mud acid.\u0000 Overall, the new single stage acid has been used to stimulate the sandstone cores successfully without acid preflush and solvent preflush. A differentiating characteristic of the fluid is that it greatly reduces the risk of treatment failure by reducing primary, secondary, and tertiary precipitation, while maintaining high dissolving power for clays. It uses a different, more cost-effective chemical pathway to stabilize problematic ions compared to traditional single-step sandstone acidizing systems. The new fluid simplifies operation by reducing the total treatment fluid volume, the total number of fluid stages, and the number of fluid types needed at the wellsite.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76112334","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}
Ike Mokogwu, Ewan Sheach, Sam Wilson, P. Hammonds, G. Graham
Detecting and mitigating near-wellbore fines migration is important in order to avoid formation damage in many gas wells. This has bearing not only on gas production but also carbon capture through the geological storage of Carbon dioxide (CO2), in pressurised, deep saline aquifers. Fines migration may occur because of weakened electrostatic forces caused by an introduced fluid which also makes fines more prone to movement by viscous drag, or where the drag forces are sufficient to physically break or lift clay crystals from their original location and transport them through the pore network. Potential near-wellbore fines migration is typically assessed via coreflood tests. In an ideal scenario, such tests will be conducted using reservoir core material, with reservoir gas at rates and pressures comparable to the reservoir. However, due to practicality and cost constraints, tests are often conducted using available outcrop core and scaled down reservoir conditions. Laboratory tests reduce higher field pressures down to lab scale. In certain scenarios, simulating the total gas flux in a given near-wellbore system is achieved by increasing gas flow rates. Although, in some investigations, the need to utilise field realistic pressures in the lab is also becoming more of a requirement. This paper aims to address differences in lab protocols by examining both field realistic and scaled down conditions to aid best practice for formation damage identification and remediation. The potential utility, and challenges associated with a variety of hydrocarbon gas analogues in scenarios where increased gas density is required is also discussed. The fines migration potential of a clay rich (Blaxter) sandstone was demonstrated using salinity and flux related fines migration methods, demonstrating that under certain conditions, selected cores are susceptible to fines migration. Test results with CO2 at low and medium pressure conditions demonstrated that pressure and flow rate variation in the laboratory had no notable effect on the fines migration of Blaxter sandstone samples, under the conditions examined. Additional tests conducted at higher pressures of 7250 psig did not yield fines migration although a 10% permeability loss was observed. While this was the case for Blaxter sandstone, caution is advised when testing with field substrate under these conditions, as reservoir rocks may be more susceptible to damage. Field cores typically display a well-developed crystal structure and surface area/volume ratios more normally associated with kaolinite booklets and platelets of clays, which may expose them to higher drag forces. Therefore, the minimal permeability reduction effects observed at high pressure may potentially be multiplied in field cores. Additional core flood tests were conducted to evaluate the use of hydrocarbon gas analogues (such dodecane) as a substitute for dense gases in core flood testing. This allows lower pressures than that would be r
{"title":"From Lab to Field 2 - Assessing Impact of Fluid Density, Salinity, and Injection Rate on Fines Migration Potential in Gas Wells","authors":"Ike Mokogwu, Ewan Sheach, Sam Wilson, P. Hammonds, G. Graham","doi":"10.2118/208868-ms","DOIUrl":"https://doi.org/10.2118/208868-ms","url":null,"abstract":"\u0000 Detecting and mitigating near-wellbore fines migration is important in order to avoid formation damage in many gas wells. This has bearing not only on gas production but also carbon capture through the geological storage of Carbon dioxide (CO2), in pressurised, deep saline aquifers. Fines migration may occur because of weakened electrostatic forces caused by an introduced fluid which also makes fines more prone to movement by viscous drag, or where the drag forces are sufficient to physically break or lift clay crystals from their original location and transport them through the pore network.\u0000 Potential near-wellbore fines migration is typically assessed via coreflood tests. In an ideal scenario, such tests will be conducted using reservoir core material, with reservoir gas at rates and pressures comparable to the reservoir. However, due to practicality and cost constraints, tests are often conducted using available outcrop core and scaled down reservoir conditions. Laboratory tests reduce higher field pressures down to lab scale. In certain scenarios, simulating the total gas flux in a given near-wellbore system is achieved by increasing gas flow rates. Although, in some investigations, the need to utilise field realistic pressures in the lab is also becoming more of a requirement. This paper aims to address differences in lab protocols by examining both field realistic and scaled down conditions to aid best practice for formation damage identification and remediation. The potential utility, and challenges associated with a variety of hydrocarbon gas analogues in scenarios where increased gas density is required is also discussed.\u0000 The fines migration potential of a clay rich (Blaxter) sandstone was demonstrated using salinity and flux related fines migration methods, demonstrating that under certain conditions, selected cores are susceptible to fines migration. Test results with CO2 at low and medium pressure conditions demonstrated that pressure and flow rate variation in the laboratory had no notable effect on the fines migration of Blaxter sandstone samples, under the conditions examined. Additional tests conducted at higher pressures of 7250 psig did not yield fines migration although a 10% permeability loss was observed. While this was the case for Blaxter sandstone, caution is advised when testing with field substrate under these conditions, as reservoir rocks may be more susceptible to damage. Field cores typically display a well-developed crystal structure and surface area/volume ratios more normally associated with kaolinite booklets and platelets of clays, which may expose them to higher drag forces. Therefore, the minimal permeability reduction effects observed at high pressure may potentially be multiplied in field cores.\u0000 Additional core flood tests were conducted to evaluate the use of hydrocarbon gas analogues (such dodecane) as a substitute for dense gases in core flood testing. This allows lower pressures than that would be r","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77195081","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}
M. Magzoub, S. Salehi, I. Hussein, M. Nasser, A. Ghalambor
Loss circulation is frequent while drilling in naturally fractured or depleted reservoirs, which is usually associated with high non-productive time (NPT). Moreover, naturally pre-existing fractures may propagate when fluid pressure inside the fractures exceeds the minimum principal stress. The primary objective of this paper is to investigate the operational performance of a quick applying polymeric pill to treat severe loss circulation in highly fractured formations. To strengthen the wellbore in the presence of large fractures, proper size and concentration of loss circulation materials (LCM) are required. In this paper, a crosslinked polymer comprised of inorganic crosslinker (Aluminum-Acetate) is used to cure severe loss circulation by completely sealing fractured or high permeable formations. To achieve this, the project investigated the rheological behavior, mechanical properties, gelation mechanisms, and the filtration of the crosslinked polymer through an artificial fracture. The effect of concentration, temperature, pH, and salinity on the stability and gelation process was also assessed. The rheological properties of polyacrylamide/Aluminum-Acetate (PAM/AlAc) in aqueous solutions, with concentrations varying from 1 to 3 wt.%, were highly affected by pH, time, and shear rates, while temperature changes have less impact. The Aluminum-Acetate has a broad operational window and can form a strong gel in temperatures ranging from 75°F to 260°F. Nanosilica (NS) in small quantities less than 1% was found to enhance the stability and strength of the polymer. The results revealed that the gelation time of the Aluminum-Acetate is controllable at pH conditions between 3.5 and 8.5, and the most stable gel was formed in the temperature range from 65°F to 212°F. Fracture sealing experiments demonstrated the ability of (PAM/AlAc) to form a strong plug with sealing pressure of up to 700 psi. In general, the Aluminum-Acetate reinforced with nanosilica has great potential applications in curing severe loss circulation in high fractured formations under a wide temperature range. This paper describes a detailed method of mixing and preparing stable and functioning polyacrylamide/Aluminum-Acetate pill for curing a severe loss of circulation. The new proposed aluminum-based salt was investigated as a potential environmentally friendly replacement for the conventional chromium acetate as crosslinkers for polyacrylamide. The paper provides a good understanding of the rheological, mechanical properties, and gelation characteristics, which are important factors affecting the spotting of these pills.
{"title":"Rapid Curing Environmentally Degradable Polymeric Pill for Loss Circulation Treatment","authors":"M. Magzoub, S. Salehi, I. Hussein, M. Nasser, A. Ghalambor","doi":"10.2118/208842-ms","DOIUrl":"https://doi.org/10.2118/208842-ms","url":null,"abstract":"\u0000 Loss circulation is frequent while drilling in naturally fractured or depleted reservoirs, which is usually associated with high non-productive time (NPT). Moreover, naturally pre-existing fractures may propagate when fluid pressure inside the fractures exceeds the minimum principal stress. The primary objective of this paper is to investigate the operational performance of a quick applying polymeric pill to treat severe loss circulation in highly fractured formations. To strengthen the wellbore in the presence of large fractures, proper size and concentration of loss circulation materials (LCM) are required. In this paper, a crosslinked polymer comprised of inorganic crosslinker (Aluminum-Acetate) is used to cure severe loss circulation by completely sealing fractured or high permeable formations. To achieve this, the project investigated the rheological behavior, mechanical properties, gelation mechanisms, and the filtration of the crosslinked polymer through an artificial fracture. The effect of concentration, temperature, pH, and salinity on the stability and gelation process was also assessed.\u0000 The rheological properties of polyacrylamide/Aluminum-Acetate (PAM/AlAc) in aqueous solutions, with concentrations varying from 1 to 3 wt.%, were highly affected by pH, time, and shear rates, while temperature changes have less impact. The Aluminum-Acetate has a broad operational window and can form a strong gel in temperatures ranging from 75°F to 260°F. Nanosilica (NS) in small quantities less than 1% was found to enhance the stability and strength of the polymer. The results revealed that the gelation time of the Aluminum-Acetate is controllable at pH conditions between 3.5 and 8.5, and the most stable gel was formed in the temperature range from 65°F to 212°F. Fracture sealing experiments demonstrated the ability of (PAM/AlAc) to form a strong plug with sealing pressure of up to 700 psi. In general, the Aluminum-Acetate reinforced with nanosilica has great potential applications in curing severe loss circulation in high fractured formations under a wide temperature range. This paper describes a detailed method of mixing and preparing stable and functioning polyacrylamide/Aluminum-Acetate pill for curing a severe loss of circulation. The new proposed aluminum-based salt was investigated as a potential environmentally friendly replacement for the conventional chromium acetate as crosslinkers for polyacrylamide. The paper provides a good understanding of the rheological, mechanical properties, and gelation characteristics, which are important factors affecting the spotting of these pills.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82028156","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}
M. Hussein, Hamad Al-Rashedi, A. Al-Naqi, S. González, Abdulaziz Erhamah, Reeham Najaf, Satinder Malik, D. Bosilca, Mohamed Ali, K. Tresco, M. Luyster
Kuwait heavy oil development target reservoir is a shallow, sub-hydrostatic and unconsolidated sandstone with relatively high porosity and permeability. Due to nature of this reservoir, well intervention operations in North Kuwait Heavy Oil Asset exhibit a higher risk of significant fluid loss that causes wellbore impairment, incremental operational costs, excess brine volume usage, and more importantly a significant impact on production deferment. The latter is due to formation damage and the time required to produce the completion fluid that is lost to the reservoir during any well intervention. The objective of using a cost-effective and less non-damaging fluid is achieved by the application of a novel customized salt system that was successfully trialed in the field. A systematic research was employed to find a suitable product/system that could be used in sub- hydrostatic conditions, able to effectively control fluid loss while retaining as near the original permeability. This new system and subsequent formulation adhered to the following criteria: Readily available Cost effective Easy to formulate and pump Easy to circulate out No long-term formation damage thus retaining original formation permeability The success of this fluid loss control material is indicated by a constant fluid level at surface after application thereby confirming its effectiveness in meeting the desired objectives. This salt system application was successfully field tested, and the results were satisfactory. During well intervention operations, the system effectively arrested fluid loss as confirmed by the fluid level measured at surface. Post operation, the well was brought back immediately to its original rate thereby confirming little to no permanent reduction to reservoir permeability. Historically, during well interventions in Kuwait Heavy Oil field, dynamic loss rates measured were in the 100 to 120 bbl per hour range. Post application of this salt system showed fluid loss rates ranging from 3 to 4 bbl per hour. To date no post acid stimulations were required to restore well production to original levels. This system was readily adapted for thermal application and compatibility with existing fluids, good bridging characteristics, as well as flow-back enhancement. This approach eliminated additional AFE costs by minimizing dynamic losses.
{"title":"Improving Fluid Loss Control During Well Intervention; A Case Study on the Use of Innovative Salt System","authors":"M. Hussein, Hamad Al-Rashedi, A. Al-Naqi, S. González, Abdulaziz Erhamah, Reeham Najaf, Satinder Malik, D. Bosilca, Mohamed Ali, K. Tresco, M. Luyster","doi":"10.2118/208833-ms","DOIUrl":"https://doi.org/10.2118/208833-ms","url":null,"abstract":"\u0000 Kuwait heavy oil development target reservoir is a shallow, sub-hydrostatic and unconsolidated sandstone with relatively high porosity and permeability.\u0000 Due to nature of this reservoir, well intervention operations in North Kuwait Heavy Oil Asset exhibit a higher risk of significant fluid loss that causes wellbore impairment, incremental operational costs, excess brine volume usage, and more importantly a significant impact on production deferment. The latter is due to formation damage and the time required to produce the completion fluid that is lost to the reservoir during any well intervention.\u0000 The objective of using a cost-effective and less non-damaging fluid is achieved by the application of a novel customized salt system that was successfully trialed in the field.\u0000 A systematic research was employed to find a suitable product/system that could be used in sub- hydrostatic conditions, able to effectively control fluid loss while retaining as near the original permeability.\u0000 This new system and subsequent formulation adhered to the following criteria:\u0000 Readily available Cost effective Easy to formulate and pump Easy to circulate out No long-term formation damage thus retaining original formation permeability\u0000 The success of this fluid loss control material is indicated by a constant fluid level at surface after application thereby confirming its effectiveness in meeting the desired objectives.\u0000 This salt system application was successfully field tested, and the results were satisfactory. During well intervention operations, the system effectively arrested fluid loss as confirmed by the fluid level measured at surface. Post operation, the well was brought back immediately to its original rate thereby confirming little to no permanent reduction to reservoir permeability.\u0000 Historically, during well interventions in Kuwait Heavy Oil field, dynamic loss rates measured were in the 100 to 120 bbl per hour range. Post application of this salt system showed fluid loss rates ranging from 3 to 4 bbl per hour. To date no post acid stimulations were required to restore well production to original levels. This system was readily adapted for thermal application and compatibility with existing fluids, good bridging characteristics, as well as flow-back enhancement. This approach eliminated additional AFE costs by minimizing dynamic losses.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77988108","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}
Tint Htoo Aung, Romain Djenani, A. Byrd, Matt Beavers, Cedric Manzoleloua, Sarah Green, B. Gadiyar
Non-aqueous gravel pack carrier fluids (GPCF) have been introduced into the industry to eliminate the risks associated with the water-based carrier fluids in the presence of reactive shale interbeds in the reservoir. However, non-aqueous GPCF pose a significant barrier to the effective deployment of post-gravel pack filter cake breaker (FCB) application because all FCB systems are water-based. Therefore, a novel approach was developed for FCB application in non-aqueous GPCF environment to improve the efficiency of the FCB and the overall well performance. The non-aqueous GPCF was redesigned from ground up to promote the better diffusion of the FCB. This was accomplished by introducing a reversible emulsifier package into the non-aqueous GPCF design which allows the gravel to change wettability from an oil-wet state to a water-wet state when a low pH solution i.e., breaker is spotted inside the sand screens after the open hoel gravel pack (OHGP). To complement this, the FCB design was deconstructed, and the in-situ breaker component was blended with the gravel. The concept was to incorporate the in-situ breaker component into the gravel pore space which would promote better diffusion of FCB through the reversible non-aqueous GPCP. The in-situ breaker component is inert to the carrier fluid until it is activated by the temperature and water posing no threat to the stability of the carrier fluid while pumping. The innovative approach was tested in the laboratory setting using ceramic disks and return to flow method to prove the concept before conducting an elaborate return permeability testing with the reservoir core plugs for the final validation. Return to flow method indicated that the novel approach could improve the results by at least 10% compared to the baseline test with no breaker application. In the return permeability tests with reservoir core plugs, the novel approach resulted in 76% of the initial permeability whereas the baseline test was only 50%. Both the tests with ceramic disks and full-sequence formation damage tests with actual reservoir cores highlighted the benefits of the novel approach for gravel packing with non-aqueous GPCF and post-gravel pack FCB scenario. Non-aqueous GPCFs are relatively new to the industry and no record of the filter cake breaker application in such environment exists. This novel approach makes the filter cake breaker application possible in non-aqueous environment and pushes the existing boundaries of filter cake breaker chemistries.
{"title":"Novel Approach in Deploying Filter Cake Breaker Post Open Hole Gravel Pack with Non-Aqueous Gravel Pack Carrier Fluid in Reservoir with Reactive Shales","authors":"Tint Htoo Aung, Romain Djenani, A. Byrd, Matt Beavers, Cedric Manzoleloua, Sarah Green, B. Gadiyar","doi":"10.2118/208827-ms","DOIUrl":"https://doi.org/10.2118/208827-ms","url":null,"abstract":"\u0000 Non-aqueous gravel pack carrier fluids (GPCF) have been introduced into the industry to eliminate the risks associated with the water-based carrier fluids in the presence of reactive shale interbeds in the reservoir. However, non-aqueous GPCF pose a significant barrier to the effective deployment of post-gravel pack filter cake breaker (FCB) application because all FCB systems are water-based. Therefore, a novel approach was developed for FCB application in non-aqueous GPCF environment to improve the efficiency of the FCB and the overall well performance.\u0000 The non-aqueous GPCF was redesigned from ground up to promote the better diffusion of the FCB. This was accomplished by introducing a reversible emulsifier package into the non-aqueous GPCF design which allows the gravel to change wettability from an oil-wet state to a water-wet state when a low pH solution i.e., breaker is spotted inside the sand screens after the open hoel gravel pack (OHGP). To complement this, the FCB design was deconstructed, and the in-situ breaker component was blended with the gravel. The concept was to incorporate the in-situ breaker component into the gravel pore space which would promote better diffusion of FCB through the reversible non-aqueous GPCP. The in-situ breaker component is inert to the carrier fluid until it is activated by the temperature and water posing no threat to the stability of the carrier fluid while pumping.\u0000 The innovative approach was tested in the laboratory setting using ceramic disks and return to flow method to prove the concept before conducting an elaborate return permeability testing with the reservoir core plugs for the final validation. Return to flow method indicated that the novel approach could improve the results by at least 10% compared to the baseline test with no breaker application. In the return permeability tests with reservoir core plugs, the novel approach resulted in 76% of the initial permeability whereas the baseline test was only 50%. Both the tests with ceramic disks and full-sequence formation damage tests with actual reservoir cores highlighted the benefits of the novel approach for gravel packing with non-aqueous GPCF and post-gravel pack FCB scenario.\u0000 Non-aqueous GPCFs are relatively new to the industry and no record of the filter cake breaker application in such environment exists. This novel approach makes the filter cake breaker application possible in non-aqueous environment and pushes the existing boundaries of filter cake breaker chemistries.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91060184","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}
Gianna Pietrangeli, M. Barry, Daniel Alvarez, Laurie Hayden, Ajay Addagalla
Offshore reservoirs in the Southwest Persian Gulf are commonly oil-wet limestone with an average permeability of 10 md. High production of hydrogen sulfide and carbon dioxide is often encountered in the oil producer wells. The tight reservoirs are commonly drilled with water-based reservoir drill-in fluid (DIF) with high concentrations of lubricants. DIFs based on sodium chloride or calcium chloride brines with corresponding optimal breakers to remove the filter cakes were formulated and evaluated to optimize production in newly drilled wells. Fluid displacement by return permeability (RP) testing was used to evaluate the fluid/limestone rock interaction. This paper discusses the compatibility of a sodium chloride-based and a calcium chloride-based DIF with limestone formation and the necessity of introducing an optimal breaker to maximize the opportunity to achieve high production rates. RP tests are widely used to determine the potential damage caused by the DIF and production enhancement after removing the DIF filter cake with a breaker. Desired results for RP tests performed with the brine-based DIF in limestone cores were a minimum of 75% regain permeability to oil production. The cores used for the RP tests were from an analogue limestone outcrop from a Mississippian formation with permeability between 9-16 md and 14-18% porosity. DIF properties were determined following API RP-13I recommended practices. Emulsion tendency for the fluids was determined by using emulsion tendency testing with a high-speed mixer to mimic shear at the pore throat. A 10.0 lb/gal sodium chloride water-based DIF with a high content of ester-based lubricant was designed for drilling a limestone formation. A high pH close to 10 was necessary to control H2S and CO2 corrosion. The return permeability of the 10.0 lb/gal fluid was 44% using LVT-200 oil as an analogue for the native hydrocarbon permeating fluid. The low return permeability was likely caused by emulsion blockages generated by the saponification of the ester-based lubricant used in the sodium chloride-based DIF. Emulsion tendency was observed between the DIF filtrate and permeating fluid in a fluid/fluid compatibility evaluation. Therefore, a breaker system was formulated and customized to enhance RP from 44% to a minimum of 75%. In contrast, a 11.0 lb/gal calcium chloride-based DIF with pH of 9.0 and same ester-based lubricant content was evaluated using a comparable limestone analogue core and demonstrated a high return permeability (>80%). Filtrate of the calcium chloride-based DIF did not form emulsions during fluid displacement in the RP test. Compatibility evaluation (return permeability) between drill-in fluids and reservoir rock is essential for oil producer wells in order to determine and avoid potential problems caused by interactions between them.
{"title":"Smart Drill-In Fluid and Breaker Design for a Limestone Reservoir for Persian Gulf Offshore Wells","authors":"Gianna Pietrangeli, M. Barry, Daniel Alvarez, Laurie Hayden, Ajay Addagalla","doi":"10.2118/208862-ms","DOIUrl":"https://doi.org/10.2118/208862-ms","url":null,"abstract":"\u0000 Offshore reservoirs in the Southwest Persian Gulf are commonly oil-wet limestone with an average permeability of 10 md. High production of hydrogen sulfide and carbon dioxide is often encountered in the oil producer wells. The tight reservoirs are commonly drilled with water-based reservoir drill-in fluid (DIF) with high concentrations of lubricants.\u0000 DIFs based on sodium chloride or calcium chloride brines with corresponding optimal breakers to remove the filter cakes were formulated and evaluated to optimize production in newly drilled wells.\u0000 Fluid displacement by return permeability (RP) testing was used to evaluate the fluid/limestone rock interaction. This paper discusses the compatibility of a sodium chloride-based and a calcium chloride-based DIF with limestone formation and the necessity of introducing an optimal breaker to maximize the opportunity to achieve high production rates.\u0000 RP tests are widely used to determine the potential damage caused by the DIF and production enhancement after removing the DIF filter cake with a breaker. Desired results for RP tests performed with the brine-based DIF in limestone cores were a minimum of 75% regain permeability to oil production. The cores used for the RP tests were from an analogue limestone outcrop from a Mississippian formation with permeability between 9-16 md and 14-18% porosity.\u0000 DIF properties were determined following API RP-13I recommended practices. Emulsion tendency for the fluids was determined by using emulsion tendency testing with a high-speed mixer to mimic shear at the pore throat.\u0000 A 10.0 lb/gal sodium chloride water-based DIF with a high content of ester-based lubricant was designed for drilling a limestone formation. A high pH close to 10 was necessary to control H2S and CO2 corrosion.\u0000 The return permeability of the 10.0 lb/gal fluid was 44% using LVT-200 oil as an analogue for the native hydrocarbon permeating fluid. The low return permeability was likely caused by emulsion blockages generated by the saponification of the ester-based lubricant used in the sodium chloride-based DIF.\u0000 Emulsion tendency was observed between the DIF filtrate and permeating fluid in a fluid/fluid compatibility evaluation. Therefore, a breaker system was formulated and customized to enhance RP from 44% to a minimum of 75%.\u0000 In contrast, a 11.0 lb/gal calcium chloride-based DIF with pH of 9.0 and same ester-based lubricant content was evaluated using a comparable limestone analogue core and demonstrated a high return permeability (>80%). Filtrate of the calcium chloride-based DIF did not form emulsions during fluid displacement in the RP test.\u0000 Compatibility evaluation (return permeability) between drill-in fluids and reservoir rock is essential for oil producer wells in order to determine and avoid potential problems caused by interactions between them.","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88148001","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}
Pub Date : 1986-12-31DOI: 10.1515/9783112493182-057
W. Braune, N. Kubicki, N. Pruß, R. Herrmann
{"title":"Subband Characteristics of the Two-Dimensional Inversion Carrier System in p-InSb Bicrystals","authors":"W. Braune, N. Kubicki, N. Pruß, R. Herrmann","doi":"10.1515/9783112493182-057","DOIUrl":"https://doi.org/10.1515/9783112493182-057","url":null,"abstract":"","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1986-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75229696","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}
Pub Date : 1986-12-31DOI: 10.1515/9783112493182-055
V. Gatalskaya
{"title":"On the Mechanism of Charge Carrier Scattering in Germanium with Point Defects under Cyclotron Resonance","authors":"V. Gatalskaya","doi":"10.1515/9783112493182-055","DOIUrl":"https://doi.org/10.1515/9783112493182-055","url":null,"abstract":"","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"171 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1986-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77514113","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}
Pub Date : 1986-12-31DOI: 10.1515/9783112493182-027
H. Conzelmann, A. Hangleiter, J. Weber
{"title":"Thallium-Related Isoelctronic Bound Excitons in Silicon. A Bistable Defect at Low Temperatures","authors":"H. Conzelmann, A. Hangleiter, J. Weber","doi":"10.1515/9783112493182-027","DOIUrl":"https://doi.org/10.1515/9783112493182-027","url":null,"abstract":"","PeriodicalId":10913,"journal":{"name":"Day 1 Wed, February 23, 2022","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1986-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78332431","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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