Zoraida Vázquez, Clayton Smith, N. Emery, Andrew G. Babey, S. Kakadjian, Keith Trego
Friction reducers (FRs) are commonly used in Slickwater fracturing operations to enhance oil and gas production. They are essential in reducing the frictional forces that develop along the pipe wall while pumping at high flow rates while placing proppant into fractures created in reservoirs. Standard friction reducers were historically designed for potable water and to carry proppant into the reservoir by pumping fluids at a high flow rate. They were designed to utilize turbulence for transport, however their proppant carrying capacity is limited. To maximize proppant loading into these unconventional wells, High Viscosity Friction Reducers (HVFRs) have been successfully introduced. They have the ability to reduce water consumption, minimizing chemical usage and require less operating equipment on location. Most importantly, they have better proppant transport capability which keeps the fractures in the rock open for long term production. However, some concerns remain of potential conductivity damage that might occur when using these high molecular weight polyacrylamide-based fluids, that constitute a HVFR, at higher concentrations. All current friction reducers are polymers with C-C backbones, which have historically been difficult to degrade on their own. Test show that these polymers can cause conductivity damage even in the presence of oxidizer breakers if not properly selected for the reservoir conditions. A novel HVFR design was developed to minimize formation damage when fracturing designs call for the use of HVFRs. The chemistry was engineered to be self-breaking at low concentrations, causing the bonds in the polymer to hydrolyze with elevated temperature and exposure over time. This approach results in a reduction of the residue left in the proppant pack upon flowback for a better clean-up process. This HVFR was used in a Permian field, where the operator saw an increase of 150% over the expected production that continued through the writing of this paper 90+ days. This paper will discuss the laboratory work done to evaluate the reduction of conductivity damage to the proppant pack as well highlight how this new engineered design translated into improved estimated ultimate recovery (EUR) on field trials in the Permian basin.
{"title":"High Viscosity Friction Reducer that Minimizes Damage to Conductivity","authors":"Zoraida Vázquez, Clayton Smith, N. Emery, Andrew G. Babey, S. Kakadjian, Keith Trego","doi":"10.2118/208835-ms","DOIUrl":"https://doi.org/10.2118/208835-ms","url":null,"abstract":"\u0000 Friction reducers (FRs) are commonly used in Slickwater fracturing operations to enhance oil and gas production. They are essential in reducing the frictional forces that develop along the pipe wall while pumping at high flow rates while placing proppant into fractures created in reservoirs. Standard friction reducers were historically designed for potable water and to carry proppant into the reservoir by pumping fluids at a high flow rate. They were designed to utilize turbulence for transport, however their proppant carrying capacity is limited. To maximize proppant loading into these unconventional wells, High Viscosity Friction Reducers (HVFRs) have been successfully introduced. They have the ability to reduce water consumption, minimizing chemical usage and require less operating equipment on location. Most importantly, they have better proppant transport capability which keeps the fractures in the rock open for long term production. However, some concerns remain of potential conductivity damage that might occur when using these high molecular weight polyacrylamide-based fluids, that constitute a HVFR, at higher concentrations. All current friction reducers are polymers with C-C backbones, which have historically been difficult to degrade on their own. Test show that these polymers can cause conductivity damage even in the presence of oxidizer breakers if not properly selected for the reservoir conditions.\u0000 A novel HVFR design was developed to minimize formation damage when fracturing designs call for the use of HVFRs. The chemistry was engineered to be self-breaking at low concentrations, causing the bonds in the polymer to hydrolyze with elevated temperature and exposure over time. This approach results in a reduction of the residue left in the proppant pack upon flowback for a better clean-up process. This HVFR was used in a Permian field, where the operator saw an increase of 150% over the expected production that continued through the writing of this paper 90+ days. This paper will discuss the laboratory work done to evaluate the reduction of conductivity damage to the proppant pack as well highlight how this new engineered design translated into improved estimated ultimate recovery (EUR) on field trials in the Permian basin.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87385713","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}
Laboratory sand retention and dynamic fluid loss/retained permeability reservoir drill-in fluid (RDIF) testing protocols are almost always run in a linear flow configuration. While these tests may provide excellent correlations and predictive curves, the most useful form of the final data would be translated into radial flow predictions for different drawdown conditions into a wellbore. An effort has been made using data from existing sand retention and dynamic fluid loss/retained permeability RDIF testing protocols to demonstrate more complete analysis of the standard data provided from the tests, including radial flow calculations. This paper provides an explanation of the test methods and data they generate, along with the laws and equations used to simplify the problem of linear-to-radial flow data. Constant drawdown sand retention testing provides gravel pack, screen, and clean formation permeability data, while Dynamic Fluid Loss/Retained Permeability RDIF testing on the unconsolidated formation material provides the final damaged screen permeability, remaining filtercake permeability, invaded formation permeability and the undamaged formation permeability. Using the combination of data from the two tests, translation from linear to radial flow calculations can be estimated for a wellbore scenario using the specific permeability measurements for each wellbore section, gathered from the original testing. Using representative wellbore data, a correlation is made between laboratory permeability measurements and flow rates and expected wellbore pressures. Step by step calculations using the Radial Flow equation, assuming steady state and single phase flow, allows a simpler conversion to more typical data seen in wellbore scenarios. Calculations have been made to simplify data from constant drawdown tests and dynamic fluid loss/retained permeability RDIF testing from linear flow in laboratory conditions to estimate radial flow for wellbore conditions. The results of this study can provide a more streamlined process to translate laboratory data from multiple tests into applicable radial flow which can be used for wellbore calculations.
{"title":"Advanced Data Analysis from Laboratory Testing for Soft-Sand Completions","authors":"Kelly Gurley, C. Fischer","doi":"10.2118/208856-ms","DOIUrl":"https://doi.org/10.2118/208856-ms","url":null,"abstract":"\u0000 Laboratory sand retention and dynamic fluid loss/retained permeability reservoir drill-in fluid (RDIF) testing protocols are almost always run in a linear flow configuration. While these tests may provide excellent correlations and predictive curves, the most useful form of the final data would be translated into radial flow predictions for different drawdown conditions into a wellbore. An effort has been made using data from existing sand retention and dynamic fluid loss/retained permeability RDIF testing protocols to demonstrate more complete analysis of the standard data provided from the tests, including radial flow calculations.\u0000 This paper provides an explanation of the test methods and data they generate, along with the laws and equations used to simplify the problem of linear-to-radial flow data. Constant drawdown sand retention testing provides gravel pack, screen, and clean formation permeability data, while Dynamic Fluid Loss/Retained Permeability RDIF testing on the unconsolidated formation material provides the final damaged screen permeability, remaining filtercake permeability, invaded formation permeability and the undamaged formation permeability. Using the combination of data from the two tests, translation from linear to radial flow calculations can be estimated for a wellbore scenario using the specific permeability measurements for each wellbore section, gathered from the original testing.\u0000 Using representative wellbore data, a correlation is made between laboratory permeability measurements and flow rates and expected wellbore pressures. Step by step calculations using the Radial Flow equation, assuming steady state and single phase flow, allows a simpler conversion to more typical data seen in wellbore scenarios. Calculations have been made to simplify data from constant drawdown tests and dynamic fluid loss/retained permeability RDIF testing from linear flow in laboratory conditions to estimate radial flow for wellbore conditions.\u0000 The results of this study can provide a more streamlined process to translate laboratory data from multiple tests into applicable radial flow which can be used for wellbore calculations.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74545226","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}
In this study, we established initial water saturation (Swi) using three techniques: (1) the dynamic displacement technique, (2) the porous plate technique, and (3) the vacuum saturation technique. A unique heterogeneous carbonate reservoir rock sample (1.5-inch diameter and 3-inches long) was used repeatedly to compare the techniques without an uncertainty of different cores. After establishing Swi by each initialization technique, the cross sections were scanned using a micro-CT scanner. The image data was processed to estimate the cross sectional fluid distribution in XY-direction. Furthermore, each areal average Swi was calculated to investigate Swi distribution in Z-direction (direction of injection). Based on the comparison of interpreted fluid distribution, pros/cons of each technique was discussed.
{"title":"Managing to Reproduce Original Carbonate Core Condition: Is Core Initialized Realistically on Three-Dimensional Geometry?","authors":"H. Yonebayashi, Takaaki Uetani, Hiromi Kaido","doi":"10.2118/208860-ms","DOIUrl":"https://doi.org/10.2118/208860-ms","url":null,"abstract":"\u0000 In this study, we established initial water saturation (Swi) using three techniques: (1) the dynamic displacement technique, (2) the porous plate technique, and (3) the vacuum saturation technique. A unique heterogeneous carbonate reservoir rock sample (1.5-inch diameter and 3-inches long) was used repeatedly to compare the techniques without an uncertainty of different cores. After establishing Swi by each initialization technique, the cross sections were scanned using a micro-CT scanner. The image data was processed to estimate the cross sectional fluid distribution in XY-direction. Furthermore, each areal average Swi was calculated to investigate Swi distribution in Z-direction (direction of injection). Based on the comparison of interpreted fluid distribution, pros/cons of each technique was discussed.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"139 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80985717","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}
As fields in the Deepwater and Ultra Deepwater areas in the Gulf of Mexico have matured, the frequency of asphaltene deposition within the reservoir has increased significantly. Operators reported that solvent treatments show initial production response but diminishing results and shorter treatment life with subsequent treatments. A field case study was undertaken to examine current best practices and identify opportunities for improvement. Areas needing improvement included targeting the less soluble age hardened asphaltene deposits, zonal coverage, and extending treatment life. This case study showed that measurable improvements were achieved on high asphaltene produing wells by utilizing new novel chemistry, better placement to facilitate longer soak times, effective diverting, and optimizing mechanical techniques.
{"title":"A Case Study: Improvement in Asphaltene Remediation by Focusing on Zonal Coverage and Flowback Efficiency","authors":"L. R. Houchin, Dorian Granizo, Joseph Conine","doi":"10.2118/208811-ms","DOIUrl":"https://doi.org/10.2118/208811-ms","url":null,"abstract":"\u0000 As fields in the Deepwater and Ultra Deepwater areas in the Gulf of Mexico have matured, the frequency of asphaltene deposition within the reservoir has increased significantly. Operators reported that solvent treatments show initial production response but diminishing results and shorter treatment life with subsequent treatments. A field case study was undertaken to examine current best practices and identify opportunities for improvement. Areas needing improvement included targeting the less soluble age hardened asphaltene deposits, zonal coverage, and extending treatment life. This case study showed that measurable improvements were achieved on high asphaltene produing wells by utilizing new novel chemistry, better placement to facilitate longer soak times, effective diverting, and optimizing mechanical techniques.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78058232","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}
Cedric Manzoleloua, C. Nguyen, A. Okhrimenko, V. Traboulay, M. Gamargo, David Li
As fields mature, they start depleting and require assistance to help extend production and enhance hydrocarbon recovery. The introduction of injector wells in producing fields is a commonly used pressure maintenance method which consists of injecting water or gas to maintain reservoir pressure and/or sweep hydrocarbons toward producer wells. Injector wells, requiring matrix injectivity, are typically drilled using reservoir drill-in fluids (RDIF) as they minimize near wellbore damage while drilling and lay down a high-quality acid-soluble filtercake (Dick et al. 2003). The slow and uniform dissolution of the filtercake is achieved by spotting a delayed breaker solution to allow time for pulling out the lower completion running string and closing the formation isolation valve (FIV) without causing losses. For two deepwater gas injector wells recently drilled in the Guyana Surinam Basin, a 11.9 lbm/gal RDIF was necessary and presented a design challenge of meeting both the deepwater reservoir drill-in and post-completion matrix injectivity requirements. A reversible non-aqueous RDIF system using a calcium bromide brine as the internal phase and formulated at 50/50 oil-water ratio (OWR) was selected to meet the drilling challenges. Such challenges included maintaining wellbore stability while drilling interbedded shale and controlling equivalent circulating density (ECD) below the fracture gradient at the desired rate of penetration (ROP). They also included depositing a thin, ultra-low permeability and acid-soluble filtercake. A newly developed breaker was customized to provide a 4-hour delay at bottom-hole temperature (250°F) permitting a safe pull out of the inner string above the FIV and then slowly dissolve the filtercake to restore near wellbore permeability and enable matrix injectivity. Both the recommended RDIF and delayed breaker formulations were d used in the field during reservoir drill-in and lower completion operations of the two deepwater gas injector wells. Post-completion well tests confirmed that the two wells have achieved maximum gas injectivity below fracture gradient, meeting customer expectations. This paper discusses the results of extensive laboratory tests that were necessary for the selection and the customization of both the RDIF and the delayed breaker and the field performance of the two fluids.
{"title":"Deepwater Gas Injector Wells: Overcoming the Challenge of Achieving Matrix Injectivity","authors":"Cedric Manzoleloua, C. Nguyen, A. Okhrimenko, V. Traboulay, M. Gamargo, David Li","doi":"10.2118/208809-ms","DOIUrl":"https://doi.org/10.2118/208809-ms","url":null,"abstract":"\u0000 As fields mature, they start depleting and require assistance to help extend production and enhance hydrocarbon recovery. The introduction of injector wells in producing fields is a commonly used pressure maintenance method which consists of injecting water or gas to maintain reservoir pressure and/or sweep hydrocarbons toward producer wells. Injector wells, requiring matrix injectivity, are typically drilled using reservoir drill-in fluids (RDIF) as they minimize near wellbore damage while drilling and lay down a high-quality acid-soluble filtercake (Dick et al. 2003). The slow and uniform dissolution of the filtercake is achieved by spotting a delayed breaker solution to allow time for pulling out the lower completion running string and closing the formation isolation valve (FIV) without causing losses.\u0000 For two deepwater gas injector wells recently drilled in the Guyana Surinam Basin, a 11.9 lbm/gal RDIF was necessary and presented a design challenge of meeting both the deepwater reservoir drill-in and post-completion matrix injectivity requirements.\u0000 A reversible non-aqueous RDIF system using a calcium bromide brine as the internal phase and formulated at 50/50 oil-water ratio (OWR) was selected to meet the drilling challenges. Such challenges included maintaining wellbore stability while drilling interbedded shale and controlling equivalent circulating density (ECD) below the fracture gradient at the desired rate of penetration (ROP). They also included depositing a thin, ultra-low permeability and acid-soluble filtercake. A newly developed breaker was customized to provide a 4-hour delay at bottom-hole temperature (250°F) permitting a safe pull out of the inner string above the FIV and then slowly dissolve the filtercake to restore near wellbore permeability and enable matrix injectivity.\u0000 Both the recommended RDIF and delayed breaker formulations were d used in the field during reservoir drill-in and lower completion operations of the two deepwater gas injector wells. Post-completion well tests confirmed that the two wells have achieved maximum gas injectivity below fracture gradient, meeting customer expectations.\u0000 This paper discusses the results of extensive laboratory tests that were necessary for the selection and the customization of both the RDIF and the delayed breaker and the field performance of the two fluids.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84852527","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}
Waterflooding presents many unique challenges, especially in the offshore environment. Cost, slot availability, and uncertainty about return on investment limit the number of water injection wells and the use of ideal flooding patterns. Furthermore, water injectivity commonly declines with time due to formation damage. Well stimulation is a routine solution to remove such damage and recover injectivity. This case study focuses on our experience with a mud-acid stimulation of a water injector in the Gulf of Mexico (GOM). When the injectivity index of an offshore water injection well had decreased over time by a factor of 4, a mud-acid stimulation was performed, and significant injectivity was recovered. The well logs show multiple high-permeability layers, which can cause issues with waterflood conformance. A non-flowback operation, also known as bullheading, was decided upon to push insoluble fines into those high-permeability layers to improve waterflood conformance. Forgoing a post-stimulation flowback also decreased the cost of the job, reduced the risk of personnel exposure to acid, and was more favorable from an environmental viewpoint. Water injectivity was monitored with traditional diagnostic Hall plots. The efficacy of the stimulation job was evaluated through Hall plots, calculated injectivity index, and skin. Pressure transient analysis (PTA) was used to determine kh products, reservoir pressures, and skin factors before and after the mud-acid stimulation. This paper presents the successful, bullhead-style acid stimulation of a water injector supporting two oil producers in the deepwater GOM.
{"title":"Water Injector Acid Stimulation: An Offshore Case Study","authors":"Hannah F. Bolingbroke, C. C. Yao","doi":"10.2118/208851-ms","DOIUrl":"https://doi.org/10.2118/208851-ms","url":null,"abstract":"\u0000 Waterflooding presents many unique challenges, especially in the offshore environment. Cost, slot availability, and uncertainty about return on investment limit the number of water injection wells and the use of ideal flooding patterns. Furthermore, water injectivity commonly declines with time due to formation damage. Well stimulation is a routine solution to remove such damage and recover injectivity. This case study focuses on our experience with a mud-acid stimulation of a water injector in the Gulf of Mexico (GOM).\u0000 When the injectivity index of an offshore water injection well had decreased over time by a factor of 4, a mud-acid stimulation was performed, and significant injectivity was recovered. The well logs show multiple high-permeability layers, which can cause issues with waterflood conformance. A non-flowback operation, also known as bullheading, was decided upon to push insoluble fines into those high-permeability layers to improve waterflood conformance. Forgoing a post-stimulation flowback also decreased the cost of the job, reduced the risk of personnel exposure to acid, and was more favorable from an environmental viewpoint.\u0000 Water injectivity was monitored with traditional diagnostic Hall plots. The efficacy of the stimulation job was evaluated through Hall plots, calculated injectivity index, and skin. Pressure transient analysis (PTA) was used to determine kh products, reservoir pressures, and skin factors before and after the mud-acid stimulation.\u0000 This paper presents the successful, bullhead-style acid stimulation of a water injector supporting two oil producers in the deepwater GOM.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73432940","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}
Gaston Emanuel Lopez, G. Vidal, Allan Claus Hedegaard, R. Maldonado
The Bandurria Field in Argentina is known for its narrow operational window due to the difference in pressure gradients while drilling through the Quintuco and Vaca Muerta formations. This scenario usually requires managed pressure drilling (MPD) and a robust well design, including four casing sections, which significantly increases the well construction cost. The operator's objective was to design an efficient and cost-effective well aligned to the current economic market conditions. Using a break-even price target of 43 USD/bbl, high-end technologies resulting in high operational costs are not cost effective and unacceptable. Therefore, the operator selected a new technology and operational method focused on the drilling fluids to increase the pressure-gradient operative window. An ultra-resistant and flexible technology was used in the open hole section in real-time while drilling. The technology is designed with the drilling fluid system so that new rock drilled would be sealed quickly. Minimizing the interaction between the drilling fluid and the formation would preserve the original formation conditions. Using this technology, it was possible to perform a flawless operation, increasing the operative window and minimizing wellbore instability while drilling through the Quintuco and Vaca Muerta formations which are characterized by interbedded carbonates/shale layers under high-pressure conditions. The offset wells on the same pad presented severe operations issues, including stuck pipe, lost circulation, and sidetracks, even with the use of MPD. The technique implemented, known as Wellbore Stabilization Technology (WSST), enabled the operator to perform a dynamic formation integrity test (DFIT) while drilling through the transition zone to evaluate the magnitude of the operative window increase and compare those results to the offset wells on the same pad. As measured in the field, the WST allowed an increase of 2-3 lb/gal beyond the fracture gradient window. The WST was later applied in six additional wells in the same area, where the drilling efficiency significantly improved compared to historical wells. Further, the operator reduced the volume of oil-based drilling fluid (OBM) used per well, minimizing drilling fluid costs and optimizing the drilling operations. A thorough laboratory analysis was performed to evaluate this novel technology's effectiveness against several high-end technologies. This innovative adoption to the drilling fluid design resulted in a significant cost reduction to drill the Bandurria Sur Field. In addition to presenting field results, including the increase in the fracture gradient window as compared to offset wells, this paper describes the prevention of lost circulation, resulting in a nearly 50% decrease in wellbore instability.
{"title":"Novel Sealing Technology Increased Wellbore Integrity While Optimizing Well Schematic in La Caverna Bandurria Sur Unconventional Field","authors":"Gaston Emanuel Lopez, G. Vidal, Allan Claus Hedegaard, R. Maldonado","doi":"10.2118/208858-ms","DOIUrl":"https://doi.org/10.2118/208858-ms","url":null,"abstract":"\u0000 The Bandurria Field in Argentina is known for its narrow operational window due to the difference in pressure gradients while drilling through the Quintuco and Vaca Muerta formations. This scenario usually requires managed pressure drilling (MPD) and a robust well design, including four casing sections, which significantly increases the well construction cost. The operator's objective was to design an efficient and cost-effective well aligned to the current economic market conditions.\u0000 Using a break-even price target of 43 USD/bbl, high-end technologies resulting in high operational costs are not cost effective and unacceptable. Therefore, the operator selected a new technology and operational method focused on the drilling fluids to increase the pressure-gradient operative window.\u0000 An ultra-resistant and flexible technology was used in the open hole section in real-time while drilling. The technology is designed with the drilling fluid system so that new rock drilled would be sealed quickly. Minimizing the interaction between the drilling fluid and the formation would preserve the original formation conditions. Using this technology, it was possible to perform a flawless operation, increasing the operative window and minimizing wellbore instability while drilling through the Quintuco and Vaca Muerta formations which are characterized by interbedded carbonates/shale layers under high-pressure conditions.\u0000 The offset wells on the same pad presented severe operations issues, including stuck pipe, lost circulation, and sidetracks, even with the use of MPD. The technique implemented, known as Wellbore Stabilization Technology (WSST), enabled the operator to perform a dynamic formation integrity test (DFIT) while drilling through the transition zone to evaluate the magnitude of the operative window increase and compare those results to the offset wells on the same pad. As measured in the field, the WST allowed an increase of 2-3 lb/gal beyond the fracture gradient window.\u0000 The WST was later applied in six additional wells in the same area, where the drilling efficiency significantly improved compared to historical wells. Further, the operator reduced the volume of oil-based drilling fluid (OBM) used per well, minimizing drilling fluid costs and optimizing the drilling operations.\u0000 A thorough laboratory analysis was performed to evaluate this novel technology's effectiveness against several high-end technologies. This innovative adoption to the drilling fluid design resulted in a significant cost reduction to drill the Bandurria Sur Field. In addition to presenting field results, including the increase in the fracture gradient window as compared to offset wells, this paper describes the prevention of lost circulation, resulting in a nearly 50% decrease in wellbore instability.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88594600","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. Byrne, L. Djayapertapa, K. Watson, N. Fleming, K. Taugbøl
To reduce the risk of screen plugging with drilling fluid solids, wellbore fluids are typically displaced to low or no solids systems before sand screen lower completions are run in to wells. Displacing the entire wellbore volume to low solids fluids can add significant cost particularly in high pressure wells. An option can be to displace the open hole section of the well only with the low solids fluid and run the lower completion through the original drilling fluid. A refinement of this process is to fill the upper hole section with the low solids fluid in order to pre-saturate the screens assembly. The movement or exchange of the two fluids as the screens are run in to the wellbore has been a significant uncertainty, until now! This work was conducted to investigate the potential for fluids to exchange as sand screen completions are run in to wells in the Field 1 Satellite and Field 2 developments. The hypothesis that fluids in the wellbore would displace fluids inside the screen assembly as the screens are run in to the well was tested. Computational Fluid Dynamics (CFD) modelling was used to simulate the movement of the lower completion in to the well and determine the rate and quantity of fluid exchange. The simulations demonstrated that when stand alone screen (SAS) completions are run in to wellbores, fluids will exchange from outside to inside the screens. This process happens at all tripping speeds examined and in all parts of the cased and open hole wellbore. The fluid exchange continues throughout the running in process, including in the open hole lower completion. There is no value in filling the top hole section with low solids completion fluid unless fluid exchange during running in can be controlled. When a one-way inflow control device (ICD) check valve is fitted to each screen joint allowing fluid to flow in to the tubing but not back out to the annulus then fluid exchange is significantly limited. Careful consideration should be given to the exchange of fluids as lower completion assemblies are run in to wells. If it is considered undesirable that the fluid in the well should enter the lower completion string as it is run in to the well then appropriate valves or flow reduction should be considered. Eliminating the requirement to fill the top hole section with low solids fluid can lead to significant cost reduction in well where expensive fluids, such as Cs formate, are required to meet the low or no solids specifications. Understanding fluid exchange in wells as screens are run in can significantly reduce the risk of formation/completion damage. The work illustrates the value in a novel application of CFD to determine the optimum well construction process.
{"title":"Understanding Fluid Exchange as Screens are Run in Hole – Mitigation of Formation and Completion Damage Risks","authors":"M. Byrne, L. Djayapertapa, K. Watson, N. Fleming, K. Taugbøl","doi":"10.2118/208852-ms","DOIUrl":"https://doi.org/10.2118/208852-ms","url":null,"abstract":"\u0000 To reduce the risk of screen plugging with drilling fluid solids, wellbore fluids are typically displaced to low or no solids systems before sand screen lower completions are run in to wells. Displacing the entire wellbore volume to low solids fluids can add significant cost particularly in high pressure wells. An option can be to displace the open hole section of the well only with the low solids fluid and run the lower completion through the original drilling fluid. A refinement of this process is to fill the upper hole section with the low solids fluid in order to pre-saturate the screens assembly. The movement or exchange of the two fluids as the screens are run in to the wellbore has been a significant uncertainty, until now!\u0000 This work was conducted to investigate the potential for fluids to exchange as sand screen completions are run in to wells in the Field 1 Satellite and Field 2 developments. The hypothesis that fluids in the wellbore would displace fluids inside the screen assembly as the screens are run in to the well was tested. Computational Fluid Dynamics (CFD) modelling was used to simulate the movement of the lower completion in to the well and determine the rate and quantity of fluid exchange.\u0000 The simulations demonstrated that when stand alone screen (SAS) completions are run in to wellbores, fluids will exchange from outside to inside the screens. This process happens at all tripping speeds examined and in all parts of the cased and open hole wellbore. The fluid exchange continues throughout the running in process, including in the open hole lower completion. There is no value in filling the top hole section with low solids completion fluid unless fluid exchange during running in can be controlled. When a one-way inflow control device (ICD) check valve is fitted to each screen joint allowing fluid to flow in to the tubing but not back out to the annulus then fluid exchange is significantly limited.\u0000 Careful consideration should be given to the exchange of fluids as lower completion assemblies are run in to wells. If it is considered undesirable that the fluid in the well should enter the lower completion string as it is run in to the well then appropriate valves or flow reduction should be considered. Eliminating the requirement to fill the top hole section with low solids fluid can lead to significant cost reduction in well where expensive fluids, such as Cs formate, are required to meet the low or no solids specifications. Understanding fluid exchange in wells as screens are run in can significantly reduce the risk of formation/completion damage. The work illustrates the value in a novel application of CFD to determine the optimum well construction process.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"137 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89142302","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}
Shuai Li, Bo Cai, Chunming He, Yuebin Gao, Jia Wang, Fei Yan, Yuting Liu, T. Yu, Xiaojun Zhong, N. Cheng, Haoyu Zhang
During the hydraulic fracturing of tight sands and shale reservoirs, ten thousands cubic meters of frac fluids were pumped into formation, while only 6-30% can be recovered. Frac fluids imbibed into formation matrix via capillary or forced pressure can cause formation damage, and this has been widely concerned. In this paper, we firstly reviewed and summarized the main damage mechanisms during the hydraulic fracturing of tight and shale reservoirs, including formation damage induced by fluids invasion, rock-fluids and fluids-fluids incompatibilities, proppants compaction and embedment, clay swelling and fines migration, chemical adsorption and particle dispersion et al. Secondly, we evaluated the formation damage via large-scale rock-block experiment (40cm×10cm×3cm cuboid size). Fluids invasion, water imbibition and flow-back process were carried out at the in-situ pressure condition to simulate the whole procedure of hydraulic fracturing. Liquid recovery and pressure profile obtained via the pressure detecting probes were used as evaluation method. What's more, nuclear magnetic resonance (NMR) methods were also used to illustrate the inner mechanism, explain the inside fluids distribution and fluids migration characteristics in different hydraulic fracturing procedure. Results showed that after frac fluid invasion, the rock permeability declined by 8-20%, and the hydrocarbon recovery decline by 25-30%, while the rock permeability can recover 3-12% after 24h's well shut-ins. Well shut-ins can increase rock permeability and this improvement is beneficial to hydrocarbon output in the later flow-back process. At the in-situ pressure condition, 4.3% more kerosene can be recovered than just at the spontaneous imbibition condition. Results also shows that invaded frac fluid forms a ‘water block’ and mainly distributes in macropores and mesopores and forms a water-block near fracture face, increasing capillary discontinuity and blocking seepage channels, while imbibition mechanism can reduce near-fracture water-blocks. A balance of displacement pressure and capillary pressure is crucial to the imbibition mechanism when considering in-situ pressure. The re-migration and distribution of the oil-water phase during the well shut-ins can weaken the water damage effect of the fracture wall, increase the relative permeability of the oil phase, and reduce the discontinuity of the capillary. Low fluids recovery after hydraulic fracturing would not all do harm to hydrocarbon recovery, sometimes it may help oil and gas extraction. Study of this paper can provide basis for oilfield field engineers to switch oil production choke and flow-back schedule management.
{"title":"Frac Fluid induced Damage in Tight Sands and Shale Reservoirs","authors":"Shuai Li, Bo Cai, Chunming He, Yuebin Gao, Jia Wang, Fei Yan, Yuting Liu, T. Yu, Xiaojun Zhong, N. Cheng, Haoyu Zhang","doi":"10.2118/208873-ms","DOIUrl":"https://doi.org/10.2118/208873-ms","url":null,"abstract":"\u0000 During the hydraulic fracturing of tight sands and shale reservoirs, ten thousands cubic meters of frac fluids were pumped into formation, while only 6-30% can be recovered. Frac fluids imbibed into formation matrix via capillary or forced pressure can cause formation damage, and this has been widely concerned.\u0000 In this paper, we firstly reviewed and summarized the main damage mechanisms during the hydraulic fracturing of tight and shale reservoirs, including formation damage induced by fluids invasion, rock-fluids and fluids-fluids incompatibilities, proppants compaction and embedment, clay swelling and fines migration, chemical adsorption and particle dispersion et al. Secondly, we evaluated the formation damage via large-scale rock-block experiment (40cm×10cm×3cm cuboid size). Fluids invasion, water imbibition and flow-back process were carried out at the in-situ pressure condition to simulate the whole procedure of hydraulic fracturing. Liquid recovery and pressure profile obtained via the pressure detecting probes were used as evaluation method. What's more, nuclear magnetic resonance (NMR) methods were also used to illustrate the inner mechanism, explain the inside fluids distribution and fluids migration characteristics in different hydraulic fracturing procedure.\u0000 Results showed that after frac fluid invasion, the rock permeability declined by 8-20%, and the hydrocarbon recovery decline by 25-30%, while the rock permeability can recover 3-12% after 24h's well shut-ins. Well shut-ins can increase rock permeability and this improvement is beneficial to hydrocarbon output in the later flow-back process. At the in-situ pressure condition, 4.3% more kerosene can be recovered than just at the spontaneous imbibition condition. Results also shows that invaded frac fluid forms a ‘water block’ and mainly distributes in macropores and mesopores and forms a water-block near fracture face, increasing capillary discontinuity and blocking seepage channels, while imbibition mechanism can reduce near-fracture water-blocks. A balance of displacement pressure and capillary pressure is crucial to the imbibition mechanism when considering in-situ pressure. The re-migration and distribution of the oil-water phase during the well shut-ins can weaken the water damage effect of the fracture wall, increase the relative permeability of the oil phase, and reduce the discontinuity of the capillary.\u0000 Low fluids recovery after hydraulic fracturing would not all do harm to hydrocarbon recovery, sometimes it may help oil and gas extraction. Study of this paper can provide basis for oilfield field engineers to switch oil production choke and flow-back schedule management.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87422583","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}
Lan Wang, Ping Li, Ting Lu, Tianhong Zhang, Wu Xiang Bai
The development of unconventional oil and gas reservoirs has become the focus of oil industry in the world, and the study of fluid flow law in unconventional reservoirs has gradually become important. As a popular additive, the analysis of the influence of nanoparticles on the fluid distribution and flow in the reservoir will have significant effect on the development strategy of the reservoir. In this paper, the effect of nanoparticle adsorption on core wettability is theoretically analyzed. The effect of hydrophilic TiO2 nanofluid on the distribution of fluid in the core was analyzed by using a typical low-permeability dense sandstone core. Through the combination of centrifugal experiment and nuclear magnetic resonance experiment, the distribution characteristics of fluid in the core before and after nanofluid treatment are compared, the nuclear magnetic resonance T2 spectrum after centrifugation is processed, and the T2 cut-off value is calibrated. The experimental results show that the mobility of internal fluid is stronger in the process of increasing centrifugal force. Compared with deionized water, the nanofluid in the small pores is easier to discharge. Based on this result, the proper use of nano additives in the production process can effectively control the fluid flow in the reservoir.
{"title":"Evaluation of Water Control Effect of Nanofluids on Unconventional Reservoirs – Laboratory Experimental Study","authors":"Lan Wang, Ping Li, Ting Lu, Tianhong Zhang, Wu Xiang Bai","doi":"10.2118/208820-ms","DOIUrl":"https://doi.org/10.2118/208820-ms","url":null,"abstract":"\u0000 The development of unconventional oil and gas reservoirs has become the focus of oil industry in the world, and the study of fluid flow law in unconventional reservoirs has gradually become important. As a popular additive, the analysis of the influence of nanoparticles on the fluid distribution and flow in the reservoir will have significant effect on the development strategy of the reservoir. In this paper, the effect of nanoparticle adsorption on core wettability is theoretically analyzed. The effect of hydrophilic TiO2 nanofluid on the distribution of fluid in the core was analyzed by using a typical low-permeability dense sandstone core. Through the combination of centrifugal experiment and nuclear magnetic resonance experiment, the distribution characteristics of fluid in the core before and after nanofluid treatment are compared, the nuclear magnetic resonance T2 spectrum after centrifugation is processed, and the T2 cut-off value is calibrated. The experimental results show that the mobility of internal fluid is stronger in the process of increasing centrifugal force. Compared with deionized water, the nanofluid in the small pores is easier to discharge. Based on this result, the proper use of nano additives in the production process can effectively control the fluid flow in the reservoir.","PeriodicalId":10891,"journal":{"name":"Day 2 Thu, February 24, 2022","volume":"363 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76415432","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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