The design methodology for H2S scavengers relies heavily on developing a test protocol that most closely simulates field applications. These include gas contact towers, direct gas production injection and multiphase treatments, such as subsea umbilical delivery lines to sea floor well heads, hydrocarbon flow lines and sour storage tank treatments. There are very few testing standards and while there are industry accepted methods, the novel methods presented fill the gaps that exist. A thorough review is made of existing test methodologies such as the static gas breakthrough test and the multiphase Parr Autoclave. Each of these has become an accepted, albeit unofficial, industry standard. Novel methods recently developed comprise the "Direct Injection Laboratory Simulator" (DILS) which, as the name suggests, represents a laboratory method of evaluating a direct gas injection application. Also included is a unique modification of the gas breakthrough test, known as the "miniature Ultrafab tower" which simulates a regenerative tower-based system, commonly in operation in the field. The results showed fascinating validation of gas direct injection and dynamic tower interactions. In some cases, the results are as expected and in others fresh insight has been obtained into any observed discrepancy between a scavenger's field performance and how it performs in the laboratory development studies. In the case of the "miniature Ultrafab tower", this ingenious piece of equipment has been proven to accurately simulate the packing typically seen in the gas contactor to enhance gas/liquid interaction as well as provides the ability to continually replenish the tower with fresh chemical during the test using an accurately controlled flow rate from an HPLC pump. These have been shown to be vitally important parameters for accurate lab to field correlation and are uniquely available from this test, for example gleaning the minimum flow rate of fresh scavenger which can control the H2S concentration to the predetermined level; exactly as is done in field operations. This novel apparatus also has a separator chamber where the spent chemical can be collected, analyzed and evaluated, exactly as is done in a field trial for a dynamic contact gas tower. Armed with a new series of test methodologies, the development of H2S scavengers can enjoy a much higher success rate in the all-important transition from laboratory to field. The test methods also give invaluable tools to trouble shooting and investigate unexpected deficiencies in products which have in the past performed as expected. This includes providing a validation method for changes and enhancements desired during the manufacture process and raw material sourcing for chemical scavengers.
{"title":"Novel H2S Scavenger Testing Methodology to Meet the Ever-Present Challenge of Simulating Scavenger Application Methods with Laboratory Testing Protocols","authors":"G. Taylor, J. Wylde, Bridgette Allan","doi":"10.2118/204356-ms","DOIUrl":"https://doi.org/10.2118/204356-ms","url":null,"abstract":"\u0000 The design methodology for H2S scavengers relies heavily on developing a test protocol that most closely simulates field applications. These include gas contact towers, direct gas production injection and multiphase treatments, such as subsea umbilical delivery lines to sea floor well heads, hydrocarbon flow lines and sour storage tank treatments. There are very few testing standards and while there are industry accepted methods, the novel methods presented fill the gaps that exist.\u0000 A thorough review is made of existing test methodologies such as the static gas breakthrough test and the multiphase Parr Autoclave. Each of these has become an accepted, albeit unofficial, industry standard. Novel methods recently developed comprise the \"Direct Injection Laboratory Simulator\" (DILS) which, as the name suggests, represents a laboratory method of evaluating a direct gas injection application. Also included is a unique modification of the gas breakthrough test, known as the \"miniature Ultrafab tower\" which simulates a regenerative tower-based system, commonly in operation in the field.\u0000 The results showed fascinating validation of gas direct injection and dynamic tower interactions. In some cases, the results are as expected and in others fresh insight has been obtained into any observed discrepancy between a scavenger's field performance and how it performs in the laboratory development studies. In the case of the \"miniature Ultrafab tower\", this ingenious piece of equipment has been proven to accurately simulate the packing typically seen in the gas contactor to enhance gas/liquid interaction as well as provides the ability to continually replenish the tower with fresh chemical during the test using an accurately controlled flow rate from an HPLC pump. These have been shown to be vitally important parameters for accurate lab to field correlation and are uniquely available from this test, for example gleaning the minimum flow rate of fresh scavenger which can control the H2S concentration to the predetermined level; exactly as is done in field operations. This novel apparatus also has a separator chamber where the spent chemical can be collected, analyzed and evaluated, exactly as is done in a field trial for a dynamic contact gas tower.\u0000 Armed with a new series of test methodologies, the development of H2S scavengers can enjoy a much higher success rate in the all-important transition from laboratory to field. The test methods also give invaluable tools to trouble shooting and investigate unexpected deficiencies in products which have in the past performed as expected. This includes providing a validation method for changes and enhancements desired during the manufacture process and raw material sourcing for chemical scavengers.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"90 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80428291","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}
Zhiwei Yue, Andrew C. Slocum, Xiaohong Lucy Tian, Linping Ke, M. Westerman, John Hazlewood
After fracturing, it is common practice to leave offshore wells shut-in from days to weeks for operational purposes. During the recent historic decline of demand for global crude, a trend has been witnessed to shut in even newly fractured wells under design for an extended period. The cause of these extended shut-ins can be attributed to various factors including operational logistics as well as economic factors. The shut-in extension brings some unique scaling challenges for well designs. In this paper, an integrated scale inhibitor (SI)/fracturing fluid package is presented with detailed laboratory prerequisites data to validate its efficacy for long-term scale protection during the extended shut-in. Utilizing seawater in offshore fracturing can provide significant cost savings to an operation. Unfortunately, in regions with barium-rich formations, the use of seawater brings tremendous barite scaling risk. In order to solve this challenge, the investigation focused on the selection of the most effective inhibitors for long-term barite inhibition under the simulated reservoir conditions. Along with the scale inhibitor selection, the crosslinked gel had to be carefully optimized to eliminate any potential negative interference the gel additives could impart to the performance of the inhibitor. Furthermore, the inhibitor was tested in the crosslinking system to meet optimum rheology requirements. Utilizing the broken gel containing the designed inhibitor package, barite precipitation could be prevented for months under the simulated testing conditions. Due to high levels of sulfate from seawater and the barium originating from the formation, barite scale formed immediately upon mixing of the two types of water in absence of the appropriate scale inhibitors. Solid scale products featuring slow releasing of the inhibitor ingredients was proven insufficient for this application. With extensive laboratory screening, the candidate chemistry demonstrated great brine-calcium tolerance, superior scale inhibition performance for both sulfate and carbonate scales, and the minimum interferences for the crosslinking engineering to meet necessary proppant carrying capacity. To mimic the gel-breaking process and heterogeneous bleeding from the formation water, the inhibitor was crosslinked with the gel at various loading rates (1 gpt to 10 gpt) and broken at the elevated reservoir temperature, then mixed with the different ratios of the formation water. Reliable scale inhibition performance was achieved for an extended period of time for up to six weeks. Incorporating SI into the fracturing stimulation package is a convenient method for operators to include a scale-control program into well-defined fracturing designs with minimal adjustment and also add significant cost-saving for offshore logistics and rig time (Fitzgerald, et al., 2008). The scale inhibitor product presented in this paper shows a superior solution to protect assets from scale deposition
压裂后，通常的做法是将海上油井关井数天至数周，以便进行作业。在最近全球原油需求的历史性下降期间，出现了一种趋势，即即使是新压裂的井，也会在较长时间内关闭。造成这种长时间停工的原因可以归结为各种因素，包括运营物流和经济因素。关井扩展为井设计带来了一些独特的结垢挑战。本文介绍了一种集成的阻垢剂/压裂液包，并提供了详细的实验室先决条件数据，以验证其在长时间关井期间的长期防垢效果。在海上压裂中使用海水可以显著节省成本。不幸的是，在富钡地层的地区，使用海水会带来巨大的重晶石结垢风险。为了解决这一挑战，研究重点是在模拟油藏条件下选择最有效的重晶石长期抑制抑制剂。在选择阻垢剂的同时，必须仔细优化交联凝胶，以消除凝胶添加剂可能对阻垢剂性能产生的任何潜在负面干扰。此外，在交联体系中对抑制剂进行了测试，以满足最佳的流变性要求。在模拟测试条件下，使用含有设计抑制剂包的破碎凝胶可以防止重晶石沉淀数月。由于海水中的硫酸盐含量高，而地层中的钡含量高，在没有适当阻垢剂的情况下，两种水混合后立即形成重晶石垢。具有缓释抑制剂成分的固体结垢产品已被证明不足以用于该应用。经过广泛的实验室筛选，候选化学物质表现出良好的盐钙耐受性，对硫酸盐和碳酸盐垢都具有优异的阻垢性能，并且在交联工程中干扰最小，以满足必要的支撑剂携带能力。为了模拟凝胶破碎过程和地层水的非均匀出油，研究人员以不同的加载速率(1 gpt至10 gpt)与凝胶交联，并在升高的油藏温度下破碎，然后与不同比例的地层水混合。在长达6周的时间内，获得了可靠的阻垢性能。将SI集成到压裂增产包中，对于作业者来说是一种方便的方法，可以将规模控制程序包含在明确的压裂设计中，只需进行最小的调整，还可以显著节省海上物流成本和钻机时间(Fitzgerald, et, 2008)。本文介绍的阻垢剂产品是一种出色的解决方案，可以在较长的关井时间内防止资产结垢。
{"title":"An Integrated Scale Protection Package for Offshore Fractured Wells Under Designed Shut-In Extension","authors":"Zhiwei Yue, Andrew C. Slocum, Xiaohong Lucy Tian, Linping Ke, M. Westerman, John Hazlewood","doi":"10.2118/204363-ms","DOIUrl":"https://doi.org/10.2118/204363-ms","url":null,"abstract":"\u0000 After fracturing, it is common practice to leave offshore wells shut-in from days to weeks for operational purposes. During the recent historic decline of demand for global crude, a trend has been witnessed to shut in even newly fractured wells under design for an extended period. The cause of these extended shut-ins can be attributed to various factors including operational logistics as well as economic factors. The shut-in extension brings some unique scaling challenges for well designs. In this paper, an integrated scale inhibitor (SI)/fracturing fluid package is presented with detailed laboratory prerequisites data to validate its efficacy for long-term scale protection during the extended shut-in.\u0000 Utilizing seawater in offshore fracturing can provide significant cost savings to an operation. Unfortunately, in regions with barium-rich formations, the use of seawater brings tremendous barite scaling risk. In order to solve this challenge, the investigation focused on the selection of the most effective inhibitors for long-term barite inhibition under the simulated reservoir conditions. Along with the scale inhibitor selection, the crosslinked gel had to be carefully optimized to eliminate any potential negative interference the gel additives could impart to the performance of the inhibitor. Furthermore, the inhibitor was tested in the crosslinking system to meet optimum rheology requirements. Utilizing the broken gel containing the designed inhibitor package, barite precipitation could be prevented for months under the simulated testing conditions.\u0000 Due to high levels of sulfate from seawater and the barium originating from the formation, barite scale formed immediately upon mixing of the two types of water in absence of the appropriate scale inhibitors. Solid scale products featuring slow releasing of the inhibitor ingredients was proven insufficient for this application. With extensive laboratory screening, the candidate chemistry demonstrated great brine-calcium tolerance, superior scale inhibition performance for both sulfate and carbonate scales, and the minimum interferences for the crosslinking engineering to meet necessary proppant carrying capacity. To mimic the gel-breaking process and heterogeneous bleeding from the formation water, the inhibitor was crosslinked with the gel at various loading rates (1 gpt to 10 gpt) and broken at the elevated reservoir temperature, then mixed with the different ratios of the formation water. Reliable scale inhibition performance was achieved for an extended period of time for up to six weeks.\u0000 Incorporating SI into the fracturing stimulation package is a convenient method for operators to include a scale-control program into well-defined fracturing designs with minimal adjustment and also add significant cost-saving for offshore logistics and rig time (Fitzgerald, et al., 2008). The scale inhibitor product presented in this paper shows a superior solution to protect assets from scale deposition ","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81579276","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The goal of acid fracturing operations is to create enough fracture roughness through non-uniform acid etching on fracture surfaces such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the formation closure stress. A detailed description of the rough acid-fracture surfaces is required for accurately predicting the acid-fracture conductivity. In this paper, a 3D acid transport model was developed to compute the geometry of acid fracture for acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since the viscous fingering mechanism is commonly applied in acid fracturing to achieve non-uniform acid etching. Carbonate reservoirs mainly consists of calcite and dolomite minerals but the mineral distribution can be quite heterogeneous. Based on the developed model, we analyzed the effect of mineral heterogeneity on the acid etching process. We compared the acid etching patterns in different carbonate reservoirs with different spatial distributions of calcite and dolomite minerals. We found that thin acid-etched channels can form in carbonate reservoirs with interbedded dolomite layers. When the reservoir heterogeneity does not favor growing thin acid-etched channels, we investigated how to utilize the acid viscous fingering technique to achieve the channeling etching pattern in such reservoirs. Through numerical simulations, we found that thin acid-etched channels can form inside acid viscous fingers. The regions between viscous fingers are left less etched and act as barriers to separate acid-etched channels. In acid fracturing treatments with viscous fingering, the etching pattern is largely dependent on the perforation spacing. With a proper perforation design, we can still achieve the channeling etching pattern even when the reservoir does not have interbedded dolomite layers.
{"title":"Modeling Acid Fracturing Treatments in Heterogeneous Carbonate Reservoirs","authors":"Rencheng Dong, M. Wheeler, Hang Su, K. Ma","doi":"10.2118/204304-ms","DOIUrl":"https://doi.org/10.2118/204304-ms","url":null,"abstract":"\u0000 The goal of acid fracturing operations is to create enough fracture roughness through non-uniform acid etching on fracture surfaces such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the formation closure stress. A detailed description of the rough acid-fracture surfaces is required for accurately predicting the acid-fracture conductivity. In this paper, a 3D acid transport model was developed to compute the geometry of acid fracture for acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since the viscous fingering mechanism is commonly applied in acid fracturing to achieve non-uniform acid etching.\u0000 Carbonate reservoirs mainly consists of calcite and dolomite minerals but the mineral distribution can be quite heterogeneous. Based on the developed model, we analyzed the effect of mineral heterogeneity on the acid etching process. We compared the acid etching patterns in different carbonate reservoirs with different spatial distributions of calcite and dolomite minerals. We found that thin acid-etched channels can form in carbonate reservoirs with interbedded dolomite layers. When the reservoir heterogeneity does not favor growing thin acid-etched channels, we investigated how to utilize the acid viscous fingering technique to achieve the channeling etching pattern in such reservoirs. Through numerical simulations, we found that thin acid-etched channels can form inside acid viscous fingers. The regions between viscous fingers are left less etched and act as barriers to separate acid-etched channels. In acid fracturing treatments with viscous fingering, the etching pattern is largely dependent on the perforation spacing. With a proper perforation design, we can still achieve the channeling etching pattern even when the reservoir does not have interbedded dolomite layers.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"176 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91477653","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}
Thenuka M. Ariyaratna, N. Obeyesekere, Tharindu S. Jayaneththi, J. Wylde
A need for more economic drilling fluids has been addressed by repurposing heavy brines typically used as completion fluids. Heavy brine corrosion inhibitors have been designed for stagnant systems. Drilling fluids are subjected to both heavy agitation and aeration through recirculation systems and atmospheric exposure during the various stages of the drilling process. This paper documents the development of heavy brine corrosion inhibitors to meet these additional drilling fluid requirements. Multiple system scenarios were presented requiring a methodical evaluation of corrosion inhibitor specifications while still maintaining performance. Due to the high density of heavy brine, traditional methods of controlling foaming were not feasible or effective. Additional product characteristics had to be modified to allow for the open mud pits where employees would be working, higher temperatures, contamination from drill cuttings, and product efficacy reduction due to absorption from solids. The product should not have any odor, should have a high flash point, and mitigate corrosion in the presence of drill cuttings, oxygen, and sour gases. Significant laboratory development and testing were done in order to develop corrosion inhibitors for use in heavy brines based on system conditions associated with completion fluids. The application of heavy brine as a drilling fluid posed new challenges involving foam control, solubility, product stability, odor control, and efficacy when mixed with drill cuttings. The key to heavy brine corrosion inhibitor efficacy is solubility in a supersaturated system. The solvent packages developed to be utilized in such environments were highly sensitive and optimized for stagnant and sealed systems. Laboratory testing was conducted utilizing rotating cylinder electrode tests with drill cuttings added to the test fluid. Product components that were found to have strong odors or low flash points were removed or replaced. Extensive foaming evaluations of multiple components helped identify problematic chemistries. Standard defoamers failed to control foaming but the combination of a unique solvent system helped to minimize foaming. The evaluations were able to minimize foaming and yield a low odor product that was suitable for open mud pits and high temperatures without compromising product efficacy. The methodology developed to transition heavy brine corrosion inhibitors from well completion applications to drilling fluid applications proved to be more complex than initially considered. This paper documents the philosophy of this transitioning and the hurdles that were overcome to ensure the final product met the unique system guidelines. The novel use of heavy brines as drilling fluids has created a need for novel chemistries to inhibit corrosion in a new application.
{"title":"Inhibiting Calcium Chloride Heavy Brines to be Used as Drilling Fluids: Hurdles Encountered in Treatment, Application, Corrosion Mitigation, Solubility, and Foaming Tendencies for Drilling Sites in Canada","authors":"Thenuka M. Ariyaratna, N. Obeyesekere, Tharindu S. Jayaneththi, J. Wylde","doi":"10.2118/204337-ms","DOIUrl":"https://doi.org/10.2118/204337-ms","url":null,"abstract":"\u0000 A need for more economic drilling fluids has been addressed by repurposing heavy brines typically used as completion fluids. Heavy brine corrosion inhibitors have been designed for stagnant systems. Drilling fluids are subjected to both heavy agitation and aeration through recirculation systems and atmospheric exposure during the various stages of the drilling process. This paper documents the development of heavy brine corrosion inhibitors to meet these additional drilling fluid requirements.\u0000 Multiple system scenarios were presented requiring a methodical evaluation of corrosion inhibitor specifications while still maintaining performance. Due to the high density of heavy brine, traditional methods of controlling foaming were not feasible or effective. Additional product characteristics had to be modified to allow for the open mud pits where employees would be working, higher temperatures, contamination from drill cuttings, and product efficacy reduction due to absorption from solids. The product should not have any odor, should have a high flash point, and mitigate corrosion in the presence of drill cuttings, oxygen, and sour gases.\u0000 Significant laboratory development and testing were done in order to develop corrosion inhibitors for use in heavy brines based on system conditions associated with completion fluids. The application of heavy brine as a drilling fluid posed new challenges involving foam control, solubility, product stability, odor control, and efficacy when mixed with drill cuttings. The key to heavy brine corrosion inhibitor efficacy is solubility in a supersaturated system. The solvent packages developed to be utilized in such environments were highly sensitive and optimized for stagnant and sealed systems. Laboratory testing was conducted utilizing rotating cylinder electrode tests with drill cuttings added to the test fluid. Product components that were found to have strong odors or low flash points were removed or replaced. Extensive foaming evaluations of multiple components helped identify problematic chemistries. Standard defoamers failed to control foaming but the combination of a unique solvent system helped to minimize foaming. The evaluations were able to minimize foaming and yield a low odor product that was suitable for open mud pits and high temperatures without compromising product efficacy.\u0000 The methodology developed to transition heavy brine corrosion inhibitors from well completion applications to drilling fluid applications proved to be more complex than initially considered. This paper documents the philosophy of this transitioning and the hurdles that were overcome to ensure the final product met the unique system guidelines. The novel use of heavy brines as drilling fluids has created a need for novel chemistries to inhibit corrosion in a new application.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91302211","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}
Over the last 30 years, chemical flooding of oil reservoirs has been broadly adopted as a technique for enhanced and incremental oil recovery around the world. Western Canadian oil producers have embraced polymer flooding to recover heavy oil, but have applied other forms of chemical flooding more sparingly. This study examines 31 chemical floods - ASP, AP, SP, alkali, and nanosurfactant floods - from mostly heavy oil fields (20 heavy oil, 10 medium oil, and one light oil). The success of the chemical floods was related to over forty reservoir and operating parameters, including water quality. We also discuss the operational challenges common in western Canada. Chemical flooding projects were identified through searches of government documents. Production and injection data were gathered using Accumap software; and reservoir and operating parameters were gathered from government documents and literature. Incremental recovery was calculated by performing decline curve analysis of the waterflooding production. The incremental recovery was the difference between the actual production during chemical flooding, and the predicted production had waterflooding continued rather than shifting to chemical flooding. Multivariate analysis was used to determine the most important parameters to the success of the chemical floods. The incremental recoveries ranged from 0 to 22% of original oil-in-place (OOIP), or 0 to 44% of OOIP per pore volume. Twenty-three of the 31 floods improved their water-oil ratios (WOR) after the start of chemical flooding. Water quality was a significant issue to the success of the chemical floods, leading to problems that were not anticipated in the planning and development stages. Some case histories are discussed to better illustrate the best practices for chemical recovery of heavy and medium oils. Water sources, management, treatment and chemistry all pose significant challenges that are often not fully assessed before starting the chemical flood projects. The review highlights challenges common to chemical flooding of heavy oil, and discusses common effects experienced as a result of water and chemistry compromises.
{"title":"Chemical Flooding in Western Canada – Successes and Operational Challenges","authors":"G. Renouf, G. Bolton, P. Nakutnyy","doi":"10.2118/204321-ms","DOIUrl":"https://doi.org/10.2118/204321-ms","url":null,"abstract":"\u0000 Over the last 30 years, chemical flooding of oil reservoirs has been broadly adopted as a technique for enhanced and incremental oil recovery around the world. Western Canadian oil producers have embraced polymer flooding to recover heavy oil, but have applied other forms of chemical flooding more sparingly. This study examines 31 chemical floods - ASP, AP, SP, alkali, and nanosurfactant floods - from mostly heavy oil fields (20 heavy oil, 10 medium oil, and one light oil). The success of the chemical floods was related to over forty reservoir and operating parameters, including water quality. We also discuss the operational challenges common in western Canada.\u0000 Chemical flooding projects were identified through searches of government documents. Production and injection data were gathered using Accumap software; and reservoir and operating parameters were gathered from government documents and literature. Incremental recovery was calculated by performing decline curve analysis of the waterflooding production. The incremental recovery was the difference between the actual production during chemical flooding, and the predicted production had waterflooding continued rather than shifting to chemical flooding. Multivariate analysis was used to determine the most important parameters to the success of the chemical floods.\u0000 The incremental recoveries ranged from 0 to 22% of original oil-in-place (OOIP), or 0 to 44% of OOIP per pore volume. Twenty-three of the 31 floods improved their water-oil ratios (WOR) after the start of chemical flooding. Water quality was a significant issue to the success of the chemical floods, leading to problems that were not anticipated in the planning and development stages. Some case histories are discussed to better illustrate the best practices for chemical recovery of heavy and medium oils. Water sources, management, treatment and chemistry all pose significant challenges that are often not fully assessed before starting the chemical flood projects. The review highlights challenges common to chemical flooding of heavy oil, and discusses common effects experienced as a result of water and chemistry compromises.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74499191","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 the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems. During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events. The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.
{"title":"Treatment of Prodigious Reactive Shale in the Permian Basin Using High-Performance Drilling Fluid: A Successful Case Study","authors":"A. Alhadi, M. Magzoub","doi":"10.2118/204341-ms","DOIUrl":"https://doi.org/10.2118/204341-ms","url":null,"abstract":"\u0000 In the Permian basin, Spraberry Trend is one of the formations that markedly contribute to the unconventional shale production in the U.S. lately. Unusual shale reactivity was encountered while drilling several horizontal wells, leading to wellbore instability issues. Consequently, shakers’ screens blockage increased the mud losses and drilling time, leading to an increased non-productive time (NPT). This paper addresses the challenges and causes of the formation instability issues resulted from shale interaction with the used drilling fluid and presents the timely actions taken to mitigate such problems.\u0000 During the drilling operation, several rock samples were collected at different depth intervals from the shale shaker. Rock samples were analyzed to identify the clay and minerals contents in the formations. The collected samples were first cleaned to remove the mud, dried, ground, and then characterized by an X-ray diffraction test (XRD) and microscopic imaging. After identifying the possible reasons for the wellbore instability, several timely actions were taken to mitigate this issue. These actions include: 1) increasing the emulsion stability, 2) increasing the water phase salinity (WPS), 3) decreasing the water phase volume, 4) adding wetting agent, 5) using wider screens for the shaker, and 6) controlling drilling parameters such as weight on bit and rotational speed. Afterward, wellbore stability, well control problem indicators, and drilling fluid properties, especially rheology, were closely monitored to identify any subsequent or unusual events.\u0000 The geological and mineralogy studies show that the drilled formation contains high smectite and illite clay content, up to 49%, which was believed to be the main reason for the unusual shale reactivity. Replacing the existing screens (200 API) with wider screens (160 and 140 API) showed an insignificant effect in mitigating the screens blockage. The adopted method of reducing the rate of penetration (ROP) and increasing the circulation time helped significantly alleviate the screens blockage by reducing the cuttings production and giving more time for hole cleaning. Furthermore, the optimal hole cleaning successfully increased the formation's stability. Adding a wetting agent to the drilling mud did not impact the cuttings aggregations; however, it led to a decrease in the rheological properties; thus, adding more concentration of the viscosifier was required to maintain the fluid rheology. Increasing the water phase salinity (WPS) to over 230k ppm and the emulsion stability to over 700 mV was considered the backbone of the treatment plan that significantly resolved the issue by inhibiting the clay. Eventually, the critical considerations were pointed out.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89904414","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}
Samridhdi Paudyal, G. Ruan, Ji-Young Lee, Xin Wang, A. Lu, Z. Dai, Chong Dai, Saebom Ko, Yue Zhao, Xuanzhu Yao, Cianna Leschied
Halite scaling has been observed in the oil/gas field with high TDS and low water cut. Due to its higher solubility, slight changes in temperature (T) and pressure (P) and evaporative effect could yield a large amount of scale, causing significant operational problems. Accurate prediction and control of halite scaling in the oil and gas production system have been a challenge. Therefore, this study aims to shed light on the prediction of halite scale formation, deposition behavior, and inhibition at close to oil field conditions. We have designed and developed a dynamic scale loop (DSL) test methodology that can be used at various T and P. The test method utilizes a change in temperature (ΔT) as a driving force to create halite supersaturation and follow with the scale precipitation/deposition. The tube blocking experiments suggest that the tube blockage can be caused by bulk precipitation and or deposition of halite precipitate. SEM analysis of the tube cross-sections indicated that tube blockage, presumably by bulk precipitation, could be seen at the beginning of the reaction tube, but deposition was observed towards the exit end of the tube. Similarly, various experimentation to simulate the water dilution at constant pressure and ΔT were conducted. The effect of the addition of water to prevent halite deposition was analyzed computationally by using ScaleSoftPitzer (SSP) software. Brine compatibility of several inhibitors were tested via bottle tests and autoclave tests and qualified inhibitors were tested in the tube blocking experiments to identify the performance of the inhibitor to treat the halite precipitation at high temperature and pressure. Overall, a robust test method was designed and developed for halite scaling under high temperature and pressure that can simulate the oil and gas production in the field.
{"title":"Development of Dynamic Tube Blocking Test Method to Study Halite Scale Deposition and Inhibition","authors":"Samridhdi Paudyal, G. Ruan, Ji-Young Lee, Xin Wang, A. Lu, Z. Dai, Chong Dai, Saebom Ko, Yue Zhao, Xuanzhu Yao, Cianna Leschied","doi":"10.2118/204389-ms","DOIUrl":"https://doi.org/10.2118/204389-ms","url":null,"abstract":"\u0000 Halite scaling has been observed in the oil/gas field with high TDS and low water cut. Due to its higher solubility, slight changes in temperature (T) and pressure (P) and evaporative effect could yield a large amount of scale, causing significant operational problems. Accurate prediction and control of halite scaling in the oil and gas production system have been a challenge. Therefore, this study aims to shed light on the prediction of halite scale formation, deposition behavior, and inhibition at close to oil field conditions. We have designed and developed a dynamic scale loop (DSL) test methodology that can be used at various T and P. The test method utilizes a change in temperature (ΔT) as a driving force to create halite supersaturation and follow with the scale precipitation/deposition. The tube blocking experiments suggest that the tube blockage can be caused by bulk precipitation and or deposition of halite precipitate. SEM analysis of the tube cross-sections indicated that tube blockage, presumably by bulk precipitation, could be seen at the beginning of the reaction tube, but deposition was observed towards the exit end of the tube. Similarly, various experimentation to simulate the water dilution at constant pressure and ΔT were conducted. The effect of the addition of water to prevent halite deposition was analyzed computationally by using ScaleSoftPitzer (SSP) software. Brine compatibility of several inhibitors were tested via bottle tests and autoclave tests and qualified inhibitors were tested in the tube blocking experiments to identify the performance of the inhibitor to treat the halite precipitation at high temperature and pressure. Overall, a robust test method was designed and developed for halite scaling under high temperature and pressure that can simulate the oil and gas production in the field.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88867213","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}
Sulphate scale can be predicted from thermodynamic models and over recent years better kinetics data has improved the prediction for field conditions. However, these models have not been able to predict the observed deposits where flow disruptions occur such as chokes, gas lift and safety valves. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that with increased turbulence there is an increase in the mass of scale observed and an increased concentration of scale inhibitor is required to prevent its formation. In this paper a field case is investigated where strontium sulphate was observed in a location downstream of a gas lift valve. Laboratory tests were conducted to confirm whether the expected scaling was observed in a low shear flow loop and also to investigate whether the location of the scale changed when additional turbulence (gas injection) was introduced to the system. The flowrate was chosen so that the shear stress generated on the test piece was approximately 1-2 Pa, similar to the value expected in typical field pipe flow. At the end of the test, the scale adhered to each of the five sections of the test piece pipe work was analysed separately to give data on both the mass and location of scale. A second test was also carried out to investigate the effect shear and turbulence induced by gas lift had on scale formation by modifying the test piece to introduce a flow of gas into the system. The test method was then used to evaluate a scale inhibitor and assess whether its performance was affected by the different flow regimes. The introduction of the ‘gas lift’ had a significant effect on the location of scale. Instead of being spread evenly throughout the test piece, the majority of the scale deposited upstream of the gas injection point. This is likely due to the induced turbulence and expansion in the tubing diameter at the T-piece increasing the residence time and thereby enhancing scale growth. A significant difference in scale location was also observed when the inhibitor dose was too low to prevent deposition and a higher dose was required to achieve complete inhibition in the ‘gas lift’ system. The findings from this study have significant impact on the design of test methods of evaluating scale risk in low saturation ratio brines and the screening methods for scale inhibitor for field application that should be utilised to develop suitable chemicals that perform better under higher shear conditions.
{"title":"Implication of Turbulent Flow Induced by Gas Lift on Strontium Sulphate Scale Formation and Control Within Production Tubing","authors":"A. Fyfe, D. Nichols, M. Jordan","doi":"10.2118/204342-ms","DOIUrl":"https://doi.org/10.2118/204342-ms","url":null,"abstract":"\u0000 Sulphate scale can be predicted from thermodynamic models and over recent years better kinetics data has improved the prediction for field conditions. However, these models have not been able to predict the observed deposits where flow disruptions occur such as chokes, gas lift and safety valves. In recent years it has been recognised that the turbulence found at these locations increases the likelihood of scale formation and experiments have been able to demonstrate that with increased turbulence there is an increase in the mass of scale observed and an increased concentration of scale inhibitor is required to prevent its formation.\u0000 In this paper a field case is investigated where strontium sulphate was observed in a location downstream of a gas lift valve. Laboratory tests were conducted to confirm whether the expected scaling was observed in a low shear flow loop and also to investigate whether the location of the scale changed when additional turbulence (gas injection) was introduced to the system. The flowrate was chosen so that the shear stress generated on the test piece was approximately 1-2 Pa, similar to the value expected in typical field pipe flow. At the end of the test, the scale adhered to each of the five sections of the test piece pipe work was analysed separately to give data on both the mass and location of scale. A second test was also carried out to investigate the effect shear and turbulence induced by gas lift had on scale formation by modifying the test piece to introduce a flow of gas into the system. The test method was then used to evaluate a scale inhibitor and assess whether its performance was affected by the different flow regimes.\u0000 The introduction of the ‘gas lift’ had a significant effect on the location of scale. Instead of being spread evenly throughout the test piece, the majority of the scale deposited upstream of the gas injection point. This is likely due to the induced turbulence and expansion in the tubing diameter at the T-piece increasing the residence time and thereby enhancing scale growth. A significant difference in scale location was also observed when the inhibitor dose was too low to prevent deposition and a higher dose was required to achieve complete inhibition in the ‘gas lift’ system.\u0000 The findings from this study have significant impact on the design of test methods of evaluating scale risk in low saturation ratio brines and the screening methods for scale inhibitor for field application that should be utilised to develop suitable chemicals that perform better under higher shear conditions.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82689710","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}
Fuwei Yu, Lida Wang, Ben Liu, Mengqi Ma, Fan Liu, Lixia Kang, Hanqiao Jiang, Junjian Li
The microfluidic experiments were conducted in this paper to clarify the flow dynamics of in situ microemulsion and further understand its EOR performances. Two kinds of 2.5D glass micromodel with varied depths of pore and throat are fabricated. One is designed for the imbibition tests, which consists of two fractures and a tight matrix. Another one is a fractured micromodel designed for the flooding tests. The micromodels are originally water wet, and can be altered to oil wet through the surface modification. At the same time, three microemulsion-forming surfactant solutions at the salinity of type I, II or III were prepared, respectively. Then the flow dynamics of these three surfactant solutions during imbibition and flooding process were visualized by the microfluidic experiments. Results show that the type I surfactant solution realizes the highest oil recovery rate in both water-wet and oil-wet imbibition micromodels. Meanwhile, the type III surfactant solution realize the highest oil recovery in both water-wet and oil-wet fractured micromodels.
{"title":"Flow Dynamics of Microemulsion-Forming Surfactants and its Implications for Enhanced Oil Recovery: A Microfluidic Study","authors":"Fuwei Yu, Lida Wang, Ben Liu, Mengqi Ma, Fan Liu, Lixia Kang, Hanqiao Jiang, Junjian Li","doi":"10.2118/204378-ms","DOIUrl":"https://doi.org/10.2118/204378-ms","url":null,"abstract":"\u0000 The microfluidic experiments were conducted in this paper to clarify the flow dynamics of in situ microemulsion and further understand its EOR performances. Two kinds of 2.5D glass micromodel with varied depths of pore and throat are fabricated. One is designed for the imbibition tests, which consists of two fractures and a tight matrix. Another one is a fractured micromodel designed for the flooding tests. The micromodels are originally water wet, and can be altered to oil wet through the surface modification. At the same time, three microemulsion-forming surfactant solutions at the salinity of type I, II or III were prepared, respectively. Then the flow dynamics of these three surfactant solutions during imbibition and flooding process were visualized by the microfluidic experiments. Results show that the type I surfactant solution realizes the highest oil recovery rate in both water-wet and oil-wet imbibition micromodels. Meanwhile, the type III surfactant solution realize the highest oil recovery in both water-wet and oil-wet fractured micromodels.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76065247","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}
Cr3+ polymer gel flooding technology is very important for enhancing oil recovery and its field trails have obtained significantly oil increment effect. However, its laboratory physical simulation experiments are rarely carried out according to real reservoir conditions. Therefore, it is very important to carry out relevant research work. Aiming at the reservoir condition of Bohai Oilfield (an offshore oilfield in China), the experimental studies on the pore structure characteristics of reservoir on the properties of Cr3+ polymer gel are carried out. The effect of different core permeability (500, 1500 and 5000 ×10−3μm2), clay content (4.5%, 9.0% and 18%), mineral type (kaolinite, montmorillonite and illite), oil saturation (79.2%, 65.4% and 49.3%) and dynamic gelation effect are thoroughly studied. Finally, its application is introduced and analyzed. Research results show that, with the increase of reservoir permeability and pore throat size, the gelation effect improves. Also, the loose cementation degree is helpful for rapid gelation. In additional, with the decrease of the content of clay and oil saturation, the gelforming effect gets better. However, the dynamic gelation strength is very low in porous media. And after chemical injection, suspension of water flooding could promote the gel-forming performance. From the field test results, this technology has obtained good effect in Bohai oilfield, due to the high permeability, severe heterogeneity, loose cementation and high water cut. In conclusion, it is very important to study on the gelation effect under the real reservoir conditions deeply. Therefore, the relevant experimental studies have been carried out comprehensively. And its mechanism are further explored. Furthermore, its field application has also been also summarized, which is vital to the success of this technology.
{"title":"Research on the Relationship Between the Pore Structure Characteristics of Reservoir and Performance of Cr3+ Polymer Gel","authors":"Xiaodong Kang, Zhe Sun, X. Wang, Jian Zhang, Shanshan Zhang","doi":"10.2118/204344-ms","DOIUrl":"https://doi.org/10.2118/204344-ms","url":null,"abstract":"\u0000 Cr3+ polymer gel flooding technology is very important for enhancing oil recovery and its field trails have obtained significantly oil increment effect. However, its laboratory physical simulation experiments are rarely carried out according to real reservoir conditions. Therefore, it is very important to carry out relevant research work.\u0000 Aiming at the reservoir condition of Bohai Oilfield (an offshore oilfield in China), the experimental studies on the pore structure characteristics of reservoir on the properties of Cr3+ polymer gel are carried out. The effect of different core permeability (500, 1500 and 5000 ×10−3μm2), clay content (4.5%, 9.0% and 18%), mineral type (kaolinite, montmorillonite and illite), oil saturation (79.2%, 65.4% and 49.3%) and dynamic gelation effect are thoroughly studied. Finally, its application is introduced and analyzed.\u0000 Research results show that, with the increase of reservoir permeability and pore throat size, the gelation effect improves. Also, the loose cementation degree is helpful for rapid gelation. In additional, with the decrease of the content of clay and oil saturation, the gelforming effect gets better. However, the dynamic gelation strength is very low in porous media. And after chemical injection, suspension of water flooding could promote the gel-forming performance. From the field test results, this technology has obtained good effect in Bohai oilfield, due to the high permeability, severe heterogeneity, loose cementation and high water cut.\u0000 In conclusion, it is very important to study on the gelation effect under the real reservoir conditions deeply. Therefore, the relevant experimental studies have been carried out comprehensively. And its mechanism are further explored. Furthermore, its field application has also been also summarized, which is vital to the success of this technology.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78729741","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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