Oilfield scale and corrosion at oil and gas wells and topside facilities are well known problems. There are many studies towards the control and mitigation of scaling risk during production. However, there has been limited research conducted to investigate the effectiveness of scale control approaches for the preservation of wells and facility during a potential long term shut-in period, which could last more than 6 months. Due to low oil price and harsh economic environment, the need to shut-in wells and facilities can become necessary for operations. Understanding of scale control for a long term period is important to ensure both subsurface and surface production integrity during the shut-in period. The right strategy and treatment approaches in scale management will reduce reservoir and facility damage as well as the resulting cost for mitigation. In this paper, we will review and assess the scale risk for different scenarios for operation shut-in periods and utilize laboratory study to improve the understanding of long-term impact and identify appropriate mitigation strategy. Simulated brine compositions from both conventional and unconventional fields are tested. Commercially available scale inhibitors are used for testing. Various conditions including temperature (131-171 °F), saturation index (1.28-1.73), pH (7.04-8.03) and ratio of scaling ions are evaluated. The tested inhibitor dosage range was 0-300 mg/L. Inhibitor-brine incompatibility was also investigated. Sulfate and carbonate scales such as barium sulfate, strontium sulfate and calcium carbonate are studied as example. This paper will provide an important guidance for the management of well shut- in scenarios for the industry, for both conventional and unconventional fields. Performance of two scale inhibitors for same water composition are demonstrated. The efficiency of scale inhibitor #2 is lower than that of inhibitor #1. A linear correlation is observed for long term scale inhibitor performance in this case. Protection time is thus predicted from data collected from the first 8-week experiments. The predicted protection time at 250 mg/L of inhibitor A and B is 100 weeks and 16 weeks respectively. The actual protection time will be compared to the predicted value. The inhibitor-rock interaction has also been preliminarily studied. The effects of inhibitor adsorption onto formation rock should be considered for chemical treatment design and performance/dosage optimization. This study provides novel information of scale control in a much longer time frame (up to 6 months). Various parameters may have effects on their long term control. Results will benefit the chemical selection and evaluation for long term well shut-in scenario. In addition, brine-inhibitor compatibility is evaluated simultaneously.
{"title":"Scale Control for Long Term Well and Facility Preservation","authors":"Chao Yan, W. Wang, Wei Wei","doi":"10.2118/204282-ms","DOIUrl":"https://doi.org/10.2118/204282-ms","url":null,"abstract":"\u0000 Oilfield scale and corrosion at oil and gas wells and topside facilities are well known problems. There are many studies towards the control and mitigation of scaling risk during production. However, there has been limited research conducted to investigate the effectiveness of scale control approaches for the preservation of wells and facility during a potential long term shut-in period, which could last more than 6 months. Due to low oil price and harsh economic environment, the need to shut-in wells and facilities can become necessary for operations. Understanding of scale control for a long term period is important to ensure both subsurface and surface production integrity during the shut-in period. The right strategy and treatment approaches in scale management will reduce reservoir and facility damage as well as the resulting cost for mitigation.\u0000 In this paper, we will review and assess the scale risk for different scenarios for operation shut-in periods and utilize laboratory study to improve the understanding of long-term impact and identify appropriate mitigation strategy. Simulated brine compositions from both conventional and unconventional fields are tested. Commercially available scale inhibitors are used for testing. Various conditions including temperature (131-171 °F), saturation index (1.28-1.73), pH (7.04-8.03) and ratio of scaling ions are evaluated. The tested inhibitor dosage range was 0-300 mg/L. Inhibitor-brine incompatibility was also investigated. Sulfate and carbonate scales such as barium sulfate, strontium sulfate and calcium carbonate are studied as example. This paper will provide an important guidance for the management of well shut- in scenarios for the industry, for both conventional and unconventional fields.\u0000 Performance of two scale inhibitors for same water composition are demonstrated. The efficiency of scale inhibitor #2 is lower than that of inhibitor #1. A linear correlation is observed for long term scale inhibitor performance in this case. Protection time is thus predicted from data collected from the first 8-week experiments. The predicted protection time at 250 mg/L of inhibitor A and B is 100 weeks and 16 weeks respectively. The actual protection time will be compared to the predicted value. The inhibitor-rock interaction has also been preliminarily studied. The effects of inhibitor adsorption onto formation rock should be considered for chemical treatment design and performance/dosage optimization.\u0000 This study provides novel information of scale control in a much longer time frame (up to 6 months). Various parameters may have effects on their long term control. Results will benefit the chemical selection and evaluation for long term well shut-in scenario. In addition, brine-inhibitor compatibility is evaluated simultaneously.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"265 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76993806","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}
Christopher S. Daeffler, Julia Fernandez del Valle, J. Elkhoury, M. Panga, Max Nikolaev, Bulat Kamaletdinov
Globally, dolomite formations are important reservoirs for oil and gas. Acid stimulation is commonly used to extend the life of carbonate reservoirs, and a good understanding of the fluid performance is essential for effective treatment design. Three acids, hydrochloric acid (HCl), emulsified HCl, and a single-phase retarded acid based on HCl, were assessed for their ability to create wormholes in Silurian dolomite under laboratory conditions using a standard core flow experiment. Select cores were imaged by X-ray computed tomography to visualize the wormhole morphology. Similar experiments in Indiana limestone was used as a control. The core flow experiments showed that the pore volume to break-through (PVbt) values for the retarded acids in Indiana limestone were less sensitive to changes in temperature overall than unmodified HCl. For Silurian dolomite though, the opposite is observed. HCl has uniformly high PVbt values at lower (200 °F) and higher (325 °F). The emulsified acid and the single-phase retarded acid are more efficient than HCl, but the difference is smaller at 325 °F. Core images revealed that all three fluids had some degree of wormhole branching at 200 °F and much less branching at 325 °F. By visual inspection, the single-phase retarded acid has less ramification than HCl and the emulsified acid. Overall, the results show that retarded acids should make effective stimulation fluids for dolomite reservoirs.
{"title":"Dolomite Stimulation with Retarded Acids","authors":"Christopher S. Daeffler, Julia Fernandez del Valle, J. Elkhoury, M. Panga, Max Nikolaev, Bulat Kamaletdinov","doi":"10.2118/204386-ms","DOIUrl":"https://doi.org/10.2118/204386-ms","url":null,"abstract":"\u0000 Globally, dolomite formations are important reservoirs for oil and gas. Acid stimulation is commonly used to extend the life of carbonate reservoirs, and a good understanding of the fluid performance is essential for effective treatment design. Three acids, hydrochloric acid (HCl), emulsified HCl, and a single-phase retarded acid based on HCl, were assessed for their ability to create wormholes in Silurian dolomite under laboratory conditions using a standard core flow experiment. Select cores were imaged by X-ray computed tomography to visualize the wormhole morphology. Similar experiments in Indiana limestone was used as a control. The core flow experiments showed that the pore volume to break-through (PVbt) values for the retarded acids in Indiana limestone were less sensitive to changes in temperature overall than unmodified HCl. For Silurian dolomite though, the opposite is observed. HCl has uniformly high PVbt values at lower (200 °F) and higher (325 °F). The emulsified acid and the single-phase retarded acid are more efficient than HCl, but the difference is smaller at 325 °F. Core images revealed that all three fluids had some degree of wormhole branching at 200 °F and much less branching at 325 °F. By visual inspection, the single-phase retarded acid has less ramification than HCl and the emulsified acid. Overall, the results show that retarded acids should make effective stimulation fluids for dolomite reservoirs.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84942411","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}
Yue Zhao, Z. Dai, Chong Dai, Samridhdi Paudyal, Xin Wang, Saebom Ko, Xuanzhu Yao, Cianna Leschied, A. Kan, M. Tomson
Mineral scale formation has always been a serious problem during production. Most scales can be treated by adding threshold scale inhibitors. Several crystallization and inhibition models have previously been reported to predict the minimum inhibitor concentration (MIC) needed to control the barite and calcite scale. Recently, more attentions have been paid to the formation of celestite scale in the oilfield. However, no related models have been developed to help determine the MIC needed for the celestite scale control. Therefore, in this study, the crystallization and inhibition kinetics data of celestite under a wide range of celestite saturation index (SI = 0.7 – 2.6), temperature (T = 25 – 90 °C), ionic strength (IS = 1.075 – 3.075 M) and pH (4 – 6.7) with one phosphonate inhibitor (diethylenetriamine penta(methylene phosphonic acid, DTPMP) and two polymeric inhibitors (phophinopolycarboxylate, PPCA and polyvinyl sulfonate, PVS) were measured by laser apparatus or collected from previous studies. Then, based on the results, the celestite crystallization and inhibition models were established accordingly. Good agreements between the experimental results and calculated results from the models can be found. By using these newly developed models, the MIC needed for three commonly seen inhibitors, DTPMP, PPCA and PVS on celestite scale control can be predicted under extensive production conditions. The developed models can fill in the blank in scaling management strategies for high Sr2+ and SO42- concentrations in the produced waters.
{"title":"A Semiempirical Model for Predicting Celestite Scale Formation and Inhibition in Oilfield Operating Conditions","authors":"Yue Zhao, Z. Dai, Chong Dai, Samridhdi Paudyal, Xin Wang, Saebom Ko, Xuanzhu Yao, Cianna Leschied, A. Kan, M. Tomson","doi":"10.2118/204372-ms","DOIUrl":"https://doi.org/10.2118/204372-ms","url":null,"abstract":"\u0000 Mineral scale formation has always been a serious problem during production. Most scales can be treated by adding threshold scale inhibitors. Several crystallization and inhibition models have previously been reported to predict the minimum inhibitor concentration (MIC) needed to control the barite and calcite scale. Recently, more attentions have been paid to the formation of celestite scale in the oilfield. However, no related models have been developed to help determine the MIC needed for the celestite scale control. Therefore, in this study, the crystallization and inhibition kinetics data of celestite under a wide range of celestite saturation index (SI = 0.7 – 2.6), temperature (T = 25 – 90 °C), ionic strength (IS = 1.075 – 3.075 M) and pH (4 – 6.7) with one phosphonate inhibitor (diethylenetriamine penta(methylene phosphonic acid, DTPMP) and two polymeric inhibitors (phophinopolycarboxylate, PPCA and polyvinyl sulfonate, PVS) were measured by laser apparatus or collected from previous studies. Then, based on the results, the celestite crystallization and inhibition models were established accordingly. Good agreements between the experimental results and calculated results from the models can be found. By using these newly developed models, the MIC needed for three commonly seen inhibitors, DTPMP, PPCA and PVS on celestite scale control can be predicted under extensive production conditions. The developed models can fill in the blank in scaling management strategies for high Sr2+ and SO42- concentrations in the produced waters.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83398205","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 water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield. This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified. In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons. Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.
{"title":"The Combined Flooding of Dispersed Particle Gel and Surfactant for Conformance Control and EOR: From Experiment to Pilot Test","authors":"Xia Yin, Tianyi Zhao, J. Yi","doi":"10.2118/204324-ms","DOIUrl":"https://doi.org/10.2118/204324-ms","url":null,"abstract":"\u0000 The water channeling and excess water production led to the decreasing formation energy in the oilfield. Therefore, the combined flooding with dispersed particle gel (DPG) and surfactant was conducted for conformance control and enhanced oil recovery in a high temperature (100-110°C) high salinity (>2.1×105mg/L) channel reservoir of block X in Tahe oilfield.\u0000 This paper reports the experimental results and pilot test for the combined flooding in a well group of Block X. In the experiment part, the interfacial tension, emulsifying capacity of the surfactant and the particle size during aging of DPG were measured, then, the conformance control and enhanced oil recovery performance of the combined flooding was evaluated by core flooding experiment. In the pilot test, the geological backgrounds and developing history of the block was introduced. Then, an integrated study of EOR and conformance control performance in the block X are analyzed by real-time monitoring and performance after treatment. In addition, the well selection criteria and flooding optimization were clarified.\u0000 In this combined flooding, DPG is applied as in-depth conformance control agent to increase the sweep efficiency, and surfactant solution slug following is used for improve the displacement efficiency. The long term stability of DPG for 15 days ensures the efficiency of in-depth conformance control and its size can increase from its original 0.543μm to 35.5μm after aging for 7 days in the 2.17×105mg/L reservoir water and at 110°C. In the optimization, it is found that 0.35% NAC-1+ 0.25% NAC-2 surfactant solution with interfacial tension 3.2×10-2mN/m can form a relatively stable emulsion easily with the dehydrated crude oil. In the double core flooding, the conformance control performance is confirmed by the diversion of fluid after combined flooding and EOR increases by 21.3%. After exploitation of Block X for 14 years, the fast decreasing formation energy due to lack of large bottom water and water fingering resulted in a decreasing production rate and increasing watercut. After combined flooding in Y well group with 1 injector and 3 producers, the average dynamic liquid level, daily production, and tracing agent breakthrough time increased, while the watercut and infectivity index decreased. The distribution rate of injected fluid and real-time monitoring also assured the conformance control performance. The oil production of this well group was increased by over 3000 tons.\u0000 Upon this throughout study of combined flooding from experiment to case study, adjusting the heterogeneity by DPG combined with increasing displacement efficiency of surfactant enhanced the oil recovery synergistically in this high salinity high temperature reservoir. The criteria for the selection and performance of combined flooding also provides practical experiences and principles for combined flooding.","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":"79352829","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}
A. Beteta, L. Boak, K. McIver, M. Jordan, R. Shields
With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. The key question being addressed in this publication is the influence of EOR chemicals, such as hydrolyzed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime for barium sulphate and calcium carbonate scale risk. Squeeze lifetime is defined as the duration of time (or produced water volume) before the minimum inhibitor concentration (MIC) is reached. This is controlled by the adsorption, and later release, of the inhibitor onto the reservoir rock and the MIC of the inhibitor selected for the produced brine. This paper builds on earlier published work investigating potential changes to inhibitor adsorption caused by polymer EOR produced and moves to the evaluation of the changes in MIC due to the presence of EOR chemical. In the static inhibitor performance bottle tests, the EOR polymer alone appeared to show some degree of inhibition performance against BaSO4, but below a level required for effective scale management. However, in combination with the inhibitor (DETPMP) at near MIC levels, the inhibition efficiency was negatively impacted by the presence of degraded HPAM EOR polymer. During dynamic tube blocking tests, the inclusion of even low levels of HPAM (2.5 ppm) were shown to reduce the differential pressure build up suggesting barite scale inhibition or reduced adhesion to the coil. Furthermore, the scale morphology produced in these tests, examined under a scanning electron microscope, was clearly impacted in the presence of HPAM. For the CaCO3 system there appears to be increasing positive impact from HPAM on CaCO3 morphology with HPAM concentration and, as observed for BaSO4, an improved performance in dynamic efficiency experiments. However, at higher HPAM concentrations (500 ppm) the precipitate was amorphous and only a minor pressure rise was observed during the tube blocking experiments. From these observations, it is clear that HPAM can impact the way both calcite and barite scale grow, especially at lower inhibitor concentrations (
{"title":"Mechanistic Understanding of the Impact of EOR Polymer on the Inhibition Mechanism and Performance of Phosphonate Scale Inhibitors","authors":"A. Beteta, L. Boak, K. McIver, M. Jordan, R. Shields","doi":"10.2118/204383-ms","DOIUrl":"https://doi.org/10.2118/204383-ms","url":null,"abstract":"With the current trend for application of Enhanced Oil Recovery (EOR) technologies, there has been much research into the possible upsets to production, from the nature of the produced fluids to changes in the scaling regime. The key question being addressed in this publication is the influence of EOR chemicals, such as hydrolyzed polyacrylamide (HPAM), on scale inhibitor (SI) squeeze lifetime for barium sulphate and calcium carbonate scale risk. Squeeze lifetime is defined as the duration of time (or produced water volume) before the minimum inhibitor concentration (MIC) is reached. This is controlled by the adsorption, and later release, of the inhibitor onto the reservoir rock and the MIC of the inhibitor selected for the produced brine. This paper builds on earlier published work investigating potential changes to inhibitor adsorption caused by polymer EOR produced and moves to the evaluation of the changes in MIC due to the presence of EOR chemical.\u0000 In the static inhibitor performance bottle tests, the EOR polymer alone appeared to show some degree of inhibition performance against BaSO4, but below a level required for effective scale management. However, in combination with the inhibitor (DETPMP) at near MIC levels, the inhibition efficiency was negatively impacted by the presence of degraded HPAM EOR polymer. During dynamic tube blocking tests, the inclusion of even low levels of HPAM (2.5 ppm) were shown to reduce the differential pressure build up suggesting barite scale inhibition or reduced adhesion to the coil. Furthermore, the scale morphology produced in these tests, examined under a scanning electron microscope, was clearly impacted in the presence of HPAM. For the CaCO3 system there appears to be increasing positive impact from HPAM on CaCO3 morphology with HPAM concentration and, as observed for BaSO4, an improved performance in dynamic efficiency experiments. However, at higher HPAM concentrations (500 ppm) the precipitate was amorphous and only a minor pressure rise was observed during the tube blocking experiments.\u0000 From these observations, it is clear that HPAM can impact the way both calcite and barite scale grow, especially at lower inhibitor concentrations (<MIC) and hence impacts the mechanism by which DETPMP can function to prevent scale nucleation and growth.\u0000 This study represents a comprehensive review of both inhibition performance in the presence of an EOR polymer and with these findings the implication to field treatment lifetimes and associated costs of scale management via scale squeeze in a field under HPAM flooding.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75832581","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}
N. Obeyesekere, J. Wylde, Thusitha Wickramarachchi, Lucious Kemp
Critical micelle concentration (CMC) is a known indicator for surfactants such as corrosion inhibitors’ ability to partition to water from two phase systems such as oil and water. Most corrosion inhibitors are surface active. At critical micelle concentration, the chemical is partitioned to water from the interface, physisorption on metallic surfaces and forms a physical barrier between steel and corrosive water. This protective barrier thus prevents corrosion initiating on the metal surface. When the applied chemical concentration is equal or higher than the CMC, the surfactant is partitioned to aqueous phase from the oil-water interface. This would lead to higher chemical availability of the inhibitor in water, preventing corrosion. Therefore, it was suggested that CMC can be used as an indicator to optimal chemical dose for corrosion control1-5. The lower the CMC of a corrosion inhibitor product, the better is this chemical for corrosion control as the availability of the chemical in the aqueous phase increases. This can achieve corrosion control with lesser amount of corrosion inhibitor product. Thus, increasing the performance of corrosion inhibitor product. In this work, the physical property, CMC, was used as an indicator to differentiate corrosion inhibitor performance. A vast array of corrosion inhibitor formulations was achieved by combinatorial chemical methods using Design of Experiment (DoE) methodologies and these arrays of chemical formulations were screened by utilizing high throughput screening (HTE)6-8, using CMC as the selection guide. To validate the concept, a known corrosion inhibitor formulation (Inhibitor Abz) was selected to optimize its efficacy. This formula contains several active ingredients and a solvent package. Three raw materials of this formulation were selected and varied in combinatorial fashion, keeping the solvents and other raw materials constant9. These three raw materials were blended in a random but in a controled manner utizing DoE and using combinatorial techniques. Instead of rapidly blending a large amount of formulations using robotics, the design of experiment (DoE) methods were utilized to constrain the number of blends. When attempting to discover the important factors, DoE gives a powerful suite of statistical methodologies10. In this work, Design Expert software utilizes DoE methods and this prediction model was used to explore a desired design space. The more relevant (not entirely random) formulations were generated by DoE methods, using Design Expert software that can effectively explore a desired design space. The Design of Experiment software mathematically analyzes the space in which fundamental properties are being measured. The development of an equally robust prescreening analysis was also developed. After blending a vast array of formulations by using automated workstation, these products were screened for CMC by utilizing an automated surface tension workstation. Several formulati
{"title":"Formulation of High-Performance Corrosion Inhibitors in the 21St Century: Robotic High Throughput Experimentation and Design of Experiments","authors":"N. Obeyesekere, J. Wylde, Thusitha Wickramarachchi, Lucious Kemp","doi":"10.2118/204353-ms","DOIUrl":"https://doi.org/10.2118/204353-ms","url":null,"abstract":"\u0000 Critical micelle concentration (CMC) is a known indicator for surfactants such as corrosion inhibitors’ ability to partition to water from two phase systems such as oil and water. Most corrosion inhibitors are surface active. At critical micelle concentration, the chemical is partitioned to water from the interface, physisorption on metallic surfaces and forms a physical barrier between steel and corrosive water. This protective barrier thus prevents corrosion initiating on the metal surface. When the applied chemical concentration is equal or higher than the CMC, the surfactant is partitioned to aqueous phase from the oil-water interface. This would lead to higher chemical availability of the inhibitor in water, preventing corrosion. Therefore, it was suggested that CMC can be used as an indicator to optimal chemical dose for corrosion control1-5. The lower the CMC of a corrosion inhibitor product, the better is this chemical for corrosion control as the availability of the chemical in the aqueous phase increases. This can achieve corrosion control with lesser amount of corrosion inhibitor product. Thus, increasing the performance of corrosion inhibitor product. In this work, the physical property, CMC, was used as an indicator to differentiate corrosion inhibitor performance.\u0000 A vast array of corrosion inhibitor formulations was achieved by combinatorial chemical methods using Design of Experiment (DoE) methodologies and these arrays of chemical formulations were screened by utilizing high throughput screening (HTE)6-8, using CMC as the selection guide. To validate the concept, a known corrosion inhibitor formulation (Inhibitor Abz) was selected to optimize its efficacy. This formula contains several active ingredients and a solvent package. Three raw materials of this formulation were selected and varied in combinatorial fashion, keeping the solvents and other raw materials constant9. These three raw materials were blended in a random but in a controled manner utizing DoE and using combinatorial techniques. Instead of rapidly blending a large amount of formulations using robotics, the design of experiment (DoE) methods were utilized to constrain the number of blends. When attempting to discover the important factors, DoE gives a powerful suite of statistical methodologies10. In this work, Design Expert software utilizes DoE methods and this prediction model was used to explore a desired design space.\u0000 The more relevant (not entirely random) formulations were generated by DoE methods, using Design Expert software that can effectively explore a desired design space. The Design of Experiment software mathematically analyzes the space in which fundamental properties are being measured. The development of an equally robust prescreening analysis was also developed. After blending a vast array of formulations by using automated workstation, these products were screened for CMC by utilizing an automated surface tension workstation. Several formulati","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80934926","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}
Wellbore instability and lost circulation are two major sources of non-productive time (NPT) in drilling operations worldwide. Non-aqueous fluid (NAF) is often chosen to mitigate this and minimize the chemical effect on wellbore instability in reactive shales. However, it may inadvertently increase the risk of losses. A simple method to optimize internal phase salinity (IPS) of NAF is presented to improve wellbore stability and mitigate the increased possibility of losses. Field cases are used to demonstrate the effects of salinity on wellbore instability and losses, and the application of the proposed method. IPS is optimized by managing bidirectional water movement between the NAF and shale formation via semi-permeable membrane. Typically, higher shale dehydration is designed for shallow reactive shale formation with high water content. Whereas, low or no dehydration is desired for deep naturally fractured or faulted formation by balancing osmotic pressure with hydrostatic pressure difference between mud pressure and pore pressure. The simple approach to managing this is as follows: The water activity profile for the shale formation (aw,shale) is developed based on geomechanical and geothermal information The water activity of drilling fluid (aw,mud) is defined through considering IPS and thermal effects The IPS of NAF is manipulated to manage whether shale dehydration is a requirement or should be avoided If the main challenge is wellbore instability in a chemically reactive shale, then the IPS should be higher than the equivalent salinity of shale formation (or aw,shale > aw, mud) If the main challenge is losses into non-reactive, competent but naturally fractured or faulted shale, then IPS should be at near balance with the formation equivalent salinity (or aw, shale ≈ aw, mud) It is important that salt (e.g. calcium chloride – CaCl2) addition during drilling operations is done judiciously. The real time monitoring of salinity variations, CaCl2 addition, water evaporation, electric stability (ES), cuttings/cavings etc. will help determine if extra salt is required. The myth of the negative effects of IPS on wellbore instability and lost circulation is dispelled by analyzing the field data. The traditional Chinese philosophy: "following Nature is the only criteria to judge if something is right" can be applied in this instance of IPS optimization. A simple and intuitive method to manage IPS is proposed to improve drilling performance.
{"title":"Optimize Internal Phase Salinity to Improve Wellbore Stability and Mitigate Lost Circulation","authors":"Jianguo Zhang, Alan Rodgerson, Stephen Edwards","doi":"10.2118/204347-ms","DOIUrl":"https://doi.org/10.2118/204347-ms","url":null,"abstract":"\u0000 Wellbore instability and lost circulation are two major sources of non-productive time (NPT) in drilling operations worldwide. Non-aqueous fluid (NAF) is often chosen to mitigate this and minimize the chemical effect on wellbore instability in reactive shales. However, it may inadvertently increase the risk of losses. A simple method to optimize internal phase salinity (IPS) of NAF is presented to improve wellbore stability and mitigate the increased possibility of losses. Field cases are used to demonstrate the effects of salinity on wellbore instability and losses, and the application of the proposed method.\u0000 IPS is optimized by managing bidirectional water movement between the NAF and shale formation via semi-permeable membrane. Typically, higher shale dehydration is designed for shallow reactive shale formation with high water content. Whereas, low or no dehydration is desired for deep naturally fractured or faulted formation by balancing osmotic pressure with hydrostatic pressure difference between mud pressure and pore pressure.\u0000 The simple approach to managing this is as follows:\u0000 The water activity profile for the shale formation (aw,shale) is developed based on geomechanical and geothermal information The water activity of drilling fluid (aw,mud) is defined through considering IPS and thermal effects The IPS of NAF is manipulated to manage whether shale dehydration is a requirement or should be avoided If the main challenge is wellbore instability in a chemically reactive shale, then the IPS should be higher than the equivalent salinity of shale formation (or aw,shale > aw, mud) If the main challenge is losses into non-reactive, competent but naturally fractured or faulted shale, then IPS should be at near balance with the formation equivalent salinity (or aw, shale ≈ aw, mud)\u0000 It is important that salt (e.g. calcium chloride – CaCl2) addition during drilling operations is done judiciously. The real time monitoring of salinity variations, CaCl2 addition, water evaporation, electric stability (ES), cuttings/cavings etc. will help determine if extra salt is required.\u0000 The myth of the negative effects of IPS on wellbore instability and lost circulation is dispelled by analyzing the field data. The traditional Chinese philosophy: \"following Nature is the only criteria to judge if something is right\" can be applied in this instance of IPS optimization. A simple and intuitive method to manage IPS is proposed to improve drilling performance.","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":"81235037","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}
V. Azari, H. Rodrigues, Alina Suieshova, O. Vazquez, E. Mackay
The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition. Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle. The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window. The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.
{"title":"Long-term Strategy Optimization of Scale Squeeze Treatment in a Carbonate Reservoir Under CO2-WAG Water-Alternating-Gas Injection","authors":"V. Azari, H. Rodrigues, Alina Suieshova, O. Vazquez, E. Mackay","doi":"10.2118/204352-ms","DOIUrl":"https://doi.org/10.2118/204352-ms","url":null,"abstract":"\u0000 The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition.\u0000 Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle.\u0000 The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window.\u0000 The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78460282","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}
Stable invert emulsion with oil wet solids is achieved using invert emulsifiers and wetting agents. This paper reviews the chemistry and performance criteria of traditional invert emulsifiers and wetting agents utilized in formulating stable invert emulsion drilling fluids. However, occasionally such stable invert emulsion drilling fluids can be destabilized due to various hostile conditions encountered during drilling operation, and can adversely impact the drilling cost. Extreme preventive measures cannot avoid such hostile conditions such as sudden water influx, excessive solids and salt contaminations during drilling. Upon solids becoming extremely water wet with "flipped emulsion", it becomes impossible to fix the drilling fluid, resulting in expensive maneuver. Often situation cannot be corrected with traditional wetting agents and emulsifiers even at high level of treatments. New innovative chemistry addresses the severe water-wetting and emulsion instability of invert emulsion under extreme challenging and hostile situations. The unique water soluble oil mud conditioner (OMC) synergistically enhances the performances of traditional oil-wetting agents and emulsifiers at very low, as little as 0.5 ppb levels of treatment. This OMC improves and extends the efficacy of the traditional invert emulsifiers and oil wetting agents resulting in reduced usage of these additives with excellent economic advantages. The 15.0 ppg, invert emulsion drilling fluids were prepared using 2-3 ppb of primary and secondary emulsifiers, and these fluids were destabilized using high shear mixer for 7-8 hours. The destabilized fluids had severe water wet solids and ES value of less than 5. These destabilized fluids, upon treating with 0.5 ppb of newly developed OMC instantly became oil-wet and shiny and ES was increased to greater than 500. To demonstrate the effectiveness of OMC in pre-treatment situation, the base fluids treated with 0.5 −1.0 ppb of OMC showed superior mud stability compared to base fluid when contaminated with sea water, fine solids, barite and high salt contaminations. The OMC is flexible in its application and can be used as pre-treatment to improve the overall performance of drilling fluids and can also be used for post-treatment to recover the drilling fluids, which have been rendered unusable.
{"title":"Innovative Surfactant Chemistry Offers the Performance Advantages to Invert Emulsion Drilling Fluids While Drilling Under Challenging Environments","authors":"Arvindbhai Patel, Ashutosh Kumar Singh, Nikhil Bidwai, Sakshi Indulkar, Vivek Gupta","doi":"10.2118/204362-ms","DOIUrl":"https://doi.org/10.2118/204362-ms","url":null,"abstract":"\u0000 Stable invert emulsion with oil wet solids is achieved using invert emulsifiers and wetting agents. This paper reviews the chemistry and performance criteria of traditional invert emulsifiers and wetting agents utilized in formulating stable invert emulsion drilling fluids. However, occasionally such stable invert emulsion drilling fluids can be destabilized due to various hostile conditions encountered during drilling operation, and can adversely impact the drilling cost. Extreme preventive measures cannot avoid such hostile conditions such as sudden water influx, excessive solids and salt contaminations during drilling. Upon solids becoming extremely water wet with \"flipped emulsion\", it becomes impossible to fix the drilling fluid, resulting in expensive maneuver. Often situation cannot be corrected with traditional wetting agents and emulsifiers even at high level of treatments.\u0000 New innovative chemistry addresses the severe water-wetting and emulsion instability of invert emulsion under extreme challenging and hostile situations. The unique water soluble oil mud conditioner (OMC) synergistically enhances the performances of traditional oil-wetting agents and emulsifiers at very low, as little as 0.5 ppb levels of treatment. This OMC improves and extends the efficacy of the traditional invert emulsifiers and oil wetting agents resulting in reduced usage of these additives with excellent economic advantages.\u0000 The 15.0 ppg, invert emulsion drilling fluids were prepared using 2-3 ppb of primary and secondary emulsifiers, and these fluids were destabilized using high shear mixer for 7-8 hours. The destabilized fluids had severe water wet solids and ES value of less than 5. These destabilized fluids, upon treating with 0.5 ppb of newly developed OMC instantly became oil-wet and shiny and ES was increased to greater than 500. To demonstrate the effectiveness of OMC in pre-treatment situation, the base fluids treated with 0.5 −1.0 ppb of OMC showed superior mud stability compared to base fluid when contaminated with sea water, fine solids, barite and high salt contaminations. The OMC is flexible in its application and can be used as pre-treatment to improve the overall performance of drilling fluids and can also be used for post-treatment to recover the drilling fluids, which have been rendered unusable.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83108713","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}
Fluorescence tagged (F-tagged) scale inhibitors are drawing more interest in the oil industry and are being applied in the field. One main reason is being easily detectable and differentiable from other scale inhibitors. However, when applied to a new oilfield, it is necessary to evaluate their thermal stability, limit of detection (LOD), and fluorescence measurement interference from other chemicals. Two F-tagged scale inhibitors were tested in this study. They are the same polymeric inhibitors with different and differentiable fluorescent tags. Both F-tagged inhibitors were able to be detected in synthetic brine and field brine from a Gulf of Mexico (GoM) field, with LOD of 1ppm. A coreflood test was also conducted for inhibitor squeeze treatment evaluation. The residual scale inhibitor in core flooding samples was measured by both fluorescence method and high performance liquid chromatography (HPLC). The results from two methods generally match with each other. This strongly indicates that the F-tag is stable on scale inhibitors and fluorescence measurement is a reliable method for scale inhibitor detection. Thermal aging test and long storage test were conducted. For both F-tagged scale inhibitors, the thermal aged samples and samples with different storage lifetime did not show significant difference on scale inhibition performance and fluorescence measurement. The two F-tagged inhibitors tested can tolerate high temperature up to at least 130°C (266°F). With proper storage, F-tagged inhibitors after long shelf storage were still as effective as fresh inhibitors. Based on all the test results in this paper, these two scale inhibitors are ready for squeeze application in GoM.
{"title":"Development of Fluorescence Tagged Scale Inhibitors for Squeeze Applications in Gulf of Mexico","authors":"Ya Liu, Dong Lee, Haiping Lu, Jeffrey Russek","doi":"10.2118/204349-ms","DOIUrl":"https://doi.org/10.2118/204349-ms","url":null,"abstract":"\u0000 Fluorescence tagged (F-tagged) scale inhibitors are drawing more interest in the oil industry and are being applied in the field. One main reason is being easily detectable and differentiable from other scale inhibitors. However, when applied to a new oilfield, it is necessary to evaluate their thermal stability, limit of detection (LOD), and fluorescence measurement interference from other chemicals. Two F-tagged scale inhibitors were tested in this study. They are the same polymeric inhibitors with different and differentiable fluorescent tags. Both F-tagged inhibitors were able to be detected in synthetic brine and field brine from a Gulf of Mexico (GoM) field, with LOD of 1ppm. A coreflood test was also conducted for inhibitor squeeze treatment evaluation. The residual scale inhibitor in core flooding samples was measured by both fluorescence method and high performance liquid chromatography (HPLC). The results from two methods generally match with each other. This strongly indicates that the F-tag is stable on scale inhibitors and fluorescence measurement is a reliable method for scale inhibitor detection. Thermal aging test and long storage test were conducted. For both F-tagged scale inhibitors, the thermal aged samples and samples with different storage lifetime did not show significant difference on scale inhibition performance and fluorescence measurement. The two F-tagged inhibitors tested can tolerate high temperature up to at least 130°C (266°F). With proper storage, F-tagged inhibitors after long shelf storage were still as effective as fresh inhibitors. Based on all the test results in this paper, these two scale inhibitors are ready for squeeze application in GoM.","PeriodicalId":11099,"journal":{"name":"Day 1 Mon, December 06, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84002974","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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