N. Bhandari, M. Bhandari, I. Littlehales, Sean Potter
Metal sulfide scaling issue in the oil and gas production continue to present significant flow assurance challenge. Recently, a novel polymeric chemistry that can effectively control FeS scale deposition in oil and gas production system was reported. However, how to manage finely dispersed FeS particulates at surface disposal facilities and whether this polymer is capable of mitigating ZnS and PbS deposition is largely unknown. Therefore, this study continues to seek an efficient treatment option for metal sulfide scale management. Static bottle tests and dynamic scale loop tests under anoxic conditions were conducted to understand the efficacy of the novel polymeric chemistry towards metal sulfide scaling control. To mimic various field conditions; individual metal sulfide (FeS, ZnS and PbS) as well as mixed scaling scenarios were simulated. Various coagulant and oxidant chemistries were tested to understand the impact of the upstream treatment on safe disposal of FeS nanoparticles at surface facilities. This novel polymeric chemistry was found to be not only effective towards FeS scaling control, but also towards dispersion of ZnS and PbS as well. The primary mechanism of metal sulfide scale deposition control is identified to be crystal growth inhibition and crystal surface modification. Laboratory test results indicated no negative impact of new chemistry on the performance of other chemicals (coagulant, oxidizer etc.). In fact, an enhanced efficiency of iron sulfide oxidation was observed possibly due to the large surface area of finely dispersed particles. A field throughput study results indicated superior performance compared to that of various incumbent chemistries. Based on the laboratory results, it is anticipated that this chemistry will provide a new treatment option for metal sulfide scaling/deposition control. Additionally, the new chemistry did not leave any negative footprint for safe disposal of metal sulfide particulate at surface. As opposed to the calcite/barite scale, nucleation inhibition of metal sulfide may not be desired as the dissolved sulfide may cause further corrosion/deposition downstream. Therefore, the value this paper brings to the management of metal sulfides is a systematic testing and evaluation approach which confirms dispersion rather than nucleation inhibition is effective control mechanism.
{"title":"Developments on Metal Sulfide Scale Management in Oil and Gas Production","authors":"N. Bhandari, M. Bhandari, I. Littlehales, Sean Potter","doi":"10.2118/204305-ms","DOIUrl":"https://doi.org/10.2118/204305-ms","url":null,"abstract":"\u0000 Metal sulfide scaling issue in the oil and gas production continue to present significant flow assurance challenge. Recently, a novel polymeric chemistry that can effectively control FeS scale deposition in oil and gas production system was reported. However, how to manage finely dispersed FeS particulates at surface disposal facilities and whether this polymer is capable of mitigating ZnS and PbS deposition is largely unknown. Therefore, this study continues to seek an efficient treatment option for metal sulfide scale management.\u0000 Static bottle tests and dynamic scale loop tests under anoxic conditions were conducted to understand the efficacy of the novel polymeric chemistry towards metal sulfide scaling control. To mimic various field conditions; individual metal sulfide (FeS, ZnS and PbS) as well as mixed scaling scenarios were simulated. Various coagulant and oxidant chemistries were tested to understand the impact of the upstream treatment on safe disposal of FeS nanoparticles at surface facilities.\u0000 This novel polymeric chemistry was found to be not only effective towards FeS scaling control, but also towards dispersion of ZnS and PbS as well. The primary mechanism of metal sulfide scale deposition control is identified to be crystal growth inhibition and crystal surface modification. Laboratory test results indicated no negative impact of new chemistry on the performance of other chemicals (coagulant, oxidizer etc.). In fact, an enhanced efficiency of iron sulfide oxidation was observed possibly due to the large surface area of finely dispersed particles. A field throughput study results indicated superior performance compared to that of various incumbent chemistries.\u0000 Based on the laboratory results, it is anticipated that this chemistry will provide a new treatment option for metal sulfide scaling/deposition control. Additionally, the new chemistry did not leave any negative footprint for safe disposal of metal sulfide particulate at surface. As opposed to the calcite/barite scale, nucleation inhibition of metal sulfide may not be desired as the dissolved sulfide may cause further corrosion/deposition downstream. Therefore, the value this paper brings to the management of metal sulfides is a systematic testing and evaluation approach which confirms dispersion rather than nucleation inhibition is effective control mechanism.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76460437","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Z. Dai, A. Kan, Yi-Tsung Lu, Cianna Leschied, Yue Zhao, Chong Dai, Xin Wang, Samridhdi Paudyal, Saebom Ko, M. Tomson
Mineral scale formation causes billions of dollars’ loss every year due to production losses and facility damages in the oil and gas industry. Accurate predictions of when, where, how much, and how fast scale will deposit in the production system and how much scale inhibitor is needed are critical for scale management. Unfortunately, there is not a sophisticated scale deposition model available, potentially due to the challenges below. First, an accurate thermodynamic model is not widely available to predict scale potential at extensive ranges of temperature, pressure, and brine compositions occurring in the oilfield. Second, due to the complex oilfield operation conditions with large variations of water, oil and gas flow rates, tubing size, surface roughness, etc., wide ranges of flow patterns and regimes can occur in the field and need to be covered in the deposition model. Third, how scale inhibitors impact the mineral deposition process is not fully understood. The objective of this study is to overcome these challenges and develop a model to predict mineral deposition at different flow conditions with or without scale inhibitors. Specifically, after decades of efforts, our group has developed one of the most accurate and widely used thermodynamic model, which was adopted in this new deposition model to predict scale potential up to 250 °C, 1,500 bars, and 6 mol/kg H2O ionic strength. In addition, the mass transfer coefficients were simulated from laminar (Re < 2300) to turbulent (Re > 3,100) flow regimes, as well as the transitional flow regimes (2300 < Re < 3,100) which occur occasionally in the oilfield using sophisticated flow dynamics models. More importantly, the new deposition model also incorporates the impacts of scale inhibitors on scale deposition which was tested and quantified with Langmuir-type kink site adsorption isotherm. The minimum inhibitor dosage required can be predicted at required protection time or maximum deposition thickness rate. This model also includes the impacts of entry-region flow regime in laminar flow, surface roughness, and laminar sublayer stability under turbulent flow. The new mineral scale deposition model was validated by our laminar tubing flow deposition experiments for barite and calcite with or without scale inhibitors and laminar-to-turbulent flow experiments in literature. The good match between experimental result and model predictions show the validity of our new model. This new mineral scale deposition model is the first sophisticated model available in the oil and gas industry that can predict mineral scale deposition in the complex oilfield conditions with and without scale inhibitors. This new mineral scale deposition model will be a useful and practical tool for oilfield scale control.
{"title":"Novel Mineral Scale Deposition Model Under Different Flow Conditions with or Without Scale Inhibitors","authors":"Z. Dai, A. Kan, Yi-Tsung Lu, Cianna Leschied, Yue Zhao, Chong Dai, Xin Wang, Samridhdi Paudyal, Saebom Ko, M. Tomson","doi":"10.2118/204373-ms","DOIUrl":"https://doi.org/10.2118/204373-ms","url":null,"abstract":"\u0000 Mineral scale formation causes billions of dollars’ loss every year due to production losses and facility damages in the oil and gas industry. Accurate predictions of when, where, how much, and how fast scale will deposit in the production system and how much scale inhibitor is needed are critical for scale management. Unfortunately, there is not a sophisticated scale deposition model available, potentially due to the challenges below. First, an accurate thermodynamic model is not widely available to predict scale potential at extensive ranges of temperature, pressure, and brine compositions occurring in the oilfield. Second, due to the complex oilfield operation conditions with large variations of water, oil and gas flow rates, tubing size, surface roughness, etc., wide ranges of flow patterns and regimes can occur in the field and need to be covered in the deposition model. Third, how scale inhibitors impact the mineral deposition process is not fully understood. The objective of this study is to overcome these challenges and develop a model to predict mineral deposition at different flow conditions with or without scale inhibitors. Specifically, after decades of efforts, our group has developed one of the most accurate and widely used thermodynamic model, which was adopted in this new deposition model to predict scale potential up to 250 °C, 1,500 bars, and 6 mol/kg H2O ionic strength. In addition, the mass transfer coefficients were simulated from laminar (Re < 2300) to turbulent (Re > 3,100) flow regimes, as well as the transitional flow regimes (2300 < Re < 3,100) which occur occasionally in the oilfield using sophisticated flow dynamics models. More importantly, the new deposition model also incorporates the impacts of scale inhibitors on scale deposition which was tested and quantified with Langmuir-type kink site adsorption isotherm. The minimum inhibitor dosage required can be predicted at required protection time or maximum deposition thickness rate. This model also includes the impacts of entry-region flow regime in laminar flow, surface roughness, and laminar sublayer stability under turbulent flow. The new mineral scale deposition model was validated by our laminar tubing flow deposition experiments for barite and calcite with or without scale inhibitors and laminar-to-turbulent flow experiments in literature. The good match between experimental result and model predictions show the validity of our new model. This new mineral scale deposition model is the first sophisticated model available in the oil and gas industry that can predict mineral scale deposition in the complex oilfield conditions with and without scale inhibitors. This new mineral scale deposition model will be a useful and practical tool for oilfield scale control.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89427894","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}
Janaina Izabel Da Silva de Aguiar, A. Mahmoudkhani, S. Ibragimova
In recent years, long-distance subsea tiebacks have become a preferred field development option for deep and ultra-deepwater production. However, conditions such as lengthy umbilical systems, high pressures and variable temperatures conditions pose challenges for the continuous injection of various flow assurance chemicals. Severe operating conditions often require relatively high volumes of diluted inhibitors to be stored and injected offshore, resulting in high CAPEX costs for the installation of large topsides chemical storage tanks and their associated weight increases. Alliance Engineering estimates a deepwater platform's topsides installed costs are within the range of $35,000-$50,000/ton. It is possible to achieve significant capital cost savings on new platform designs if the dosage rates and subsequently offshore storage volumes of the highest usage production chemicals such as asphaltene inhibitors could be significantly reduced. This paper presents information on a new class of biosurfactants that are bio-based and eco-acceptable with potentials for development of ultra-low dose asphaltene inhibitors for offshore applications. Asphaltenes were extracted from chemical free crude oil samples and a curve of solubility with different ratios of heptane was obtained for each sample in order to determine the best conditions to perform the screening tests. A new class of glycolipid biosurfactants (GLP-U) was developed as an asphaltene dispersants effective at low concentrations for use in offshore applications. The new GLP-U biosurfactants are eco-acceptable and soluble in the organic solvents commonly used in offshore production chemicals. GLP-U were proved to be effective in dispersing and preventing precipitation of isolated asphaltenes at dosage rates as low as 25 mg/L (active substance), while for comparison a dodecylbenzesulfonic acid-based inhibitor provided inhibition at significantly higher concentrations (at least 40 times more).
{"title":"Ultra-Low Dose Asphaltene Inhibitors for Offshore Applications: Myth or Reality","authors":"Janaina Izabel Da Silva de Aguiar, A. Mahmoudkhani, S. Ibragimova","doi":"10.2118/204357-ms","DOIUrl":"https://doi.org/10.2118/204357-ms","url":null,"abstract":"\u0000 In recent years, long-distance subsea tiebacks have become a preferred field development option for deep and ultra-deepwater production. However, conditions such as lengthy umbilical systems, high pressures and variable temperatures conditions pose challenges for the continuous injection of various flow assurance chemicals. Severe operating conditions often require relatively high volumes of diluted inhibitors to be stored and injected offshore, resulting in high CAPEX costs for the installation of large topsides chemical storage tanks and their associated weight increases. Alliance Engineering estimates a deepwater platform's topsides installed costs are within the range of $35,000-$50,000/ton. It is possible to achieve significant capital cost savings on new platform designs if the dosage rates and subsequently offshore storage volumes of the highest usage production chemicals such as asphaltene inhibitors could be significantly reduced. This paper presents information on a new class of biosurfactants that are bio-based and eco-acceptable with potentials for development of ultra-low dose asphaltene inhibitors for offshore applications. Asphaltenes were extracted from chemical free crude oil samples and a curve of solubility with different ratios of heptane was obtained for each sample in order to determine the best conditions to perform the screening tests. A new class of glycolipid biosurfactants (GLP-U) was developed as an asphaltene dispersants effective at low concentrations for use in offshore applications. The new GLP-U biosurfactants are eco-acceptable and soluble in the organic solvents commonly used in offshore production chemicals. GLP-U were proved to be effective in dispersing and preventing precipitation of isolated asphaltenes at dosage rates as low as 25 mg/L (active substance), while for comparison a dodecylbenzesulfonic acid-based inhibitor provided inhibition at significantly higher concentrations (at least 40 times more).","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"256 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79536468","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}
Yanqing Wang, Zhe Liu, Xiang Li, Shiqian Xu, Jun Lu
Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.
天然地球化学数据是指采出水中的天然离子浓度，它包含了重要的储层信息，但很少被开发。为了更好地了解储层，一些离子被用作保守示踪剂。然而，仅使用保守离子会限制地球化学数据的应用，因为大多数离子是非保守的，可能与地层岩石相互作用或与其他离子发生反应。此外，错误地将非保守离子当作保守离子可能会导致意想不到的结果。为了进一步挖掘非保守性天然地球化学信息，将离子与岩石基质之间的相互作用整合到储层模拟器中，以描述多孔介质中非保守性离子的输运。硼是一种很有前途的非保守离子，用它来说明非保守离子的应用。在此基础上，利用ES-MDA (ensemble smooth multiple data assimilation)算法对硼浓度数据与产水量、产油量进行同化，对储层模型进行改进。结果表明，在历史拟合过程中加入非保守离子数据不仅可以进一步改善渗透率场，而且可以预测粘土含量的分布，从而提高了利用硼数据确定注入水突破率的准确性。然而，在历史匹配过程中，错误地将非保守离子视为保守离子，会降低储层模型的准确性。
{"title":"Seawater Breakthrough Monitoring and Reservoir-Model Improvement Using Natural Boron","authors":"Yanqing Wang, Zhe Liu, Xiang Li, Shiqian Xu, Jun Lu","doi":"10.2118/204306-ms","DOIUrl":"https://doi.org/10.2118/204306-ms","url":null,"abstract":"\u0000 Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74992327","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}
Kiran Gawas, C. Khandekar, Katrina Akita, J. Ngo, John Hazlewood
Deposition of high molecular weight paraffins and subsequent plugging is one of the most prevalent flow assurance risks in both onshore and offshore oil and gas production. Several thermal (e.g., insulation, heat treatment), mechanical (e.g., pigging, cutting), and chemical (e.g., paraffin crystal modifiers, dispersants, and solvents) techniques are used for wax deposition prevention and remediation. Various chemistries such as long-chain poly alkyl acrylates, olefin vinyl acetate copolymers, alkyl phenol resins and esterified olefin maleic anhydride polymers are used as wax crystal modifiers. This study investigates the impact of the alpha olefin maleic anhydride co-polymers structure on the composition and deposition of paraffin. Eight different crude samples from condensates to black oils with API gravity in the range of 30 to 50° were studied. The focus of this research is on paraffin inhibitors’ effectiveness in reducing paraffin deposition that is driven by thermal driving force between the bulk oil and the pipe wall. Inhibitor performance was measured by cold finger testing. Three different alpha olefin (short, medium and long) maleic anhydrides esterified with different fatty alcohols with varying chain lengths were tested for performance. The impact of selected chemicals on amount and composition of paraffin deposit under different test conditions was studied. Wax deposit composition was characterized using high temperature gas chromatography (HTGC) and differential scanning calorimetry (DSC) techniques. Effect of pendant side chain length as well as the composition and molecular weight of the alpha-olefin backbone on paraffin inhibition is presented. Additionally, the impact of test conditions on the composition and hence the performance of the selected chemicals is investigated. We present our findings on selective inhibition of lower molecular weight paraffin depending on the composition of the oil, leaving a much harder deposit rich in high molecular weight paraffin. This is an important observation since a hard deposit would be extremely difficult to remediate in the field and should be avoided. In summary this work provides guidelines for tailoring paraffin inhibitor molecules based on crude oil composition and field conditions, through a systematic structure-performance study.
{"title":"Optimize Performance Through Customization of Paraffin Inhibitor Molecular Structure","authors":"Kiran Gawas, C. Khandekar, Katrina Akita, J. Ngo, John Hazlewood","doi":"10.2118/204298-ms","DOIUrl":"https://doi.org/10.2118/204298-ms","url":null,"abstract":"\u0000 Deposition of high molecular weight paraffins and subsequent plugging is one of the most prevalent flow assurance risks in both onshore and offshore oil and gas production. Several thermal (e.g., insulation, heat treatment), mechanical (e.g., pigging, cutting), and chemical (e.g., paraffin crystal modifiers, dispersants, and solvents) techniques are used for wax deposition prevention and remediation. Various chemistries such as long-chain poly alkyl acrylates, olefin vinyl acetate copolymers, alkyl phenol resins and esterified olefin maleic anhydride polymers are used as wax crystal modifiers. This study investigates the impact of the alpha olefin maleic anhydride co-polymers structure on the composition and deposition of paraffin. Eight different crude samples from condensates to black oils with API gravity in the range of 30 to 50° were studied.\u0000 The focus of this research is on paraffin inhibitors’ effectiveness in reducing paraffin deposition that is driven by thermal driving force between the bulk oil and the pipe wall. Inhibitor performance was measured by cold finger testing. Three different alpha olefin (short, medium and long) maleic anhydrides esterified with different fatty alcohols with varying chain lengths were tested for performance. The impact of selected chemicals on amount and composition of paraffin deposit under different test conditions was studied. Wax deposit composition was characterized using high temperature gas chromatography (HTGC) and differential scanning calorimetry (DSC) techniques.\u0000 Effect of pendant side chain length as well as the composition and molecular weight of the alpha-olefin backbone on paraffin inhibition is presented. Additionally, the impact of test conditions on the composition and hence the performance of the selected chemicals is investigated. We present our findings on selective inhibition of lower molecular weight paraffin depending on the composition of the oil, leaving a much harder deposit rich in high molecular weight paraffin. This is an important observation since a hard deposit would be extremely difficult to remediate in the field and should be avoided.\u0000 In summary this work provides guidelines for tailoring paraffin inhibitor molecules based on crude oil composition and field conditions, through a systematic structure-performance study.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"116 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75997915","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}
Chong Dai, Z. Dai, Samiridhdi Paudyal, Saebom Ko, Yue Zhao, Xin Wang, Xuanzhu Yao, A. Kan, M. Tomson
Calcite, as one of the most common scales in oilfield can be inhibited by common scale inhibitors. The measurement of calcite nucleation and inhibition is a challenge, because of the difficulty to control pH as a result of CO2 partitioning in and out of the aqueous phase. A new kinetic turbidity test method was developed so that the partial pressure of CO2, pH, and SI can be precisely controlled. Calcite nucleation and inhibition batch tests were conducted under various conditions (SI = 0.24-2.41, T = 4-175 °C, and pH = 5.5-7.5) in the presence of common phosphonate and polymeric inhibitors. Based on experimental results, calcite nucleation and inhibition semi-empirical models are proposed, and the logarithm of the predicted induction time is in good agreement with the measured induction time. The models are also validated with laboratory and field observations. Furthermore, a new BCC CSTR Inhibition (BCIn) test method that applied the Continuous Stirred Tank Reactor (CSTR) theory has been developed, for the first time. This BCIn method was used for calcite inhibitor screening tests and minimum inhibitor concentration (MIC) estimation. By only running one experiment (< 1 hour) for each inhibitor, BCIn method selected the effective inhibitors among 18 common inhibitors under the conditions of SI = 1.23 at 90 °C and pH = 6. It was also found that the critical concentration (Ccrit) from BCIn method has a correlation with the MIC from batch tests. This study provided a simple and reliable solution for conducting calcite scale inhibition tests in an efficient and low-cost way. Furthermore, the newly developed prediction models can be used as guidance for laboratory tests and field applications, potentially saving enormous amounts of time and money.
{"title":"New Kinetic Turbidity Test Method and Prediction Model for Calcite Inhibition","authors":"Chong Dai, Z. Dai, Samiridhdi Paudyal, Saebom Ko, Yue Zhao, Xin Wang, Xuanzhu Yao, A. Kan, M. Tomson","doi":"10.2118/204398-ms","DOIUrl":"https://doi.org/10.2118/204398-ms","url":null,"abstract":"\u0000 Calcite, as one of the most common scales in oilfield can be inhibited by common scale inhibitors. The measurement of calcite nucleation and inhibition is a challenge, because of the difficulty to control pH as a result of CO2 partitioning in and out of the aqueous phase. A new kinetic turbidity test method was developed so that the partial pressure of CO2, pH, and SI can be precisely controlled. Calcite nucleation and inhibition batch tests were conducted under various conditions (SI = 0.24-2.41, T = 4-175 °C, and pH = 5.5-7.5) in the presence of common phosphonate and polymeric inhibitors. Based on experimental results, calcite nucleation and inhibition semi-empirical models are proposed, and the logarithm of the predicted induction time is in good agreement with the measured induction time. The models are also validated with laboratory and field observations. Furthermore, a new BCC CSTR Inhibition (BCIn) test method that applied the Continuous Stirred Tank Reactor (CSTR) theory has been developed, for the first time. This BCIn method was used for calcite inhibitor screening tests and minimum inhibitor concentration (MIC) estimation. By only running one experiment (< 1 hour) for each inhibitor, BCIn method selected the effective inhibitors among 18 common inhibitors under the conditions of SI = 1.23 at 90 °C and pH = 6. It was also found that the critical concentration (Ccrit) from BCIn method has a correlation with the MIC from batch tests. This study provided a simple and reliable solution for conducting calcite scale inhibition tests in an efficient and low-cost way. Furthermore, the newly developed prediction models can be used as guidance for laboratory tests and field applications, potentially saving enormous amounts of time and money.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"104 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87871848","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}
Philip Ayazi, N. Peregoy, Gabriel H. Monreal, F. Zamora
Friction reducers (FRs) are essential additives for water used in hydraulic fracturing treatments for shale reservoirs. These polymers swell and unfurl in the frac water so that polymer chains align along the direction of flow to inhibit turbulence thereby reducing friction at high flow rates. Source water ion content, application pH, and compatibility with the formation are key drivers in deciding which FR chemistries are fit-for-purpose for the operation, balancing desired fluid performance with treatment economics. This investigation explores zeta potential measurement as a novel and meaningful analytical metric to correlate chemical and rheological properties of FRs in a range of source water qualities with their friction reducing performance. The approach of this investigation involves measuring zeta potential of frac fluids formulated using anionic or cationic FRs in waters with varying ionic activity over a range of FR concentrations and pH. The evaluation encompasses a variety of FRs spanning general purpose materials to more sophisticated additives designed to function in fluids with higher concentrations of salt. Dry FR materials as well as corresponding slurry or emulsion forms of the additives are tested. Monovalent and divalent salts and mixtures thereof are used in brine formulations. FR characterization is performed including rheological sweeps, viscoelasticity measurements, and flow loop tests. Results from this study support the conclusion that zeta potential measurement can be used during the FR screening process as a viable supplement to industry standard tests for assessing FR performance in brine.
{"title":"Screening Friction Reducer Performance Using Zeta Potential","authors":"Philip Ayazi, N. Peregoy, Gabriel H. Monreal, F. Zamora","doi":"10.2118/204303-ms","DOIUrl":"https://doi.org/10.2118/204303-ms","url":null,"abstract":"\u0000 Friction reducers (FRs) are essential additives for water used in hydraulic fracturing treatments for shale reservoirs. These polymers swell and unfurl in the frac water so that polymer chains align along the direction of flow to inhibit turbulence thereby reducing friction at high flow rates. Source water ion content, application pH, and compatibility with the formation are key drivers in deciding which FR chemistries are fit-for-purpose for the operation, balancing desired fluid performance with treatment economics. This investigation explores zeta potential measurement as a novel and meaningful analytical metric to correlate chemical and rheological properties of FRs in a range of source water qualities with their friction reducing performance. The approach of this investigation involves measuring zeta potential of frac fluids formulated using anionic or cationic FRs in waters with varying ionic activity over a range of FR concentrations and pH. The evaluation encompasses a variety of FRs spanning general purpose materials to more sophisticated additives designed to function in fluids with higher concentrations of salt. Dry FR materials as well as corresponding slurry or emulsion forms of the additives are tested. Monovalent and divalent salts and mixtures thereof are used in brine formulations. FR characterization is performed including rheological sweeps, viscoelasticity measurements, and flow loop tests. Results from this study support the conclusion that zeta potential measurement can be used during the FR screening process as a viable supplement to industry standard tests for assessing FR performance in brine.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 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":"87046108","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}
This research examines the use of 75nm Zinc Oxide nanoparticles (Nano ZnO) and Polyethylene Butene (PEB) in reducing the viscosity of Nigerian waxy crude oil. The rheology of the crude oil was studied by measuring the viscosity and shear stress of crude samples contaminated with varying concentration of PEB (500ppm, 1000ppm, 2000ppm, 3000ppm, 4000ppm and 5000ppm), varying concentrations of Nano ZnO (1wt%, 2wt%, 3wt% and 4wt%) and different blends of PEB and Nano ZnO at temperatures of between 10°C to 35°C and shear rates from 1.7 to 1020s-1. From Rheological Modelling analysis conducted, the Power law pseudoplastic model was the best fit for the experimental data with a regression coefficient of 0.99. Analysis of crude sample before addition of inhibitor showed evidence of non-Newtonian fluid behaviour as the shear stress-shear rate relationship curves were nonlinear due to wax precipitation at low temperatures (10°C to 15°C). The waxy crude demonstrated shear thinning behaviour with increasing shear rates (increasing turbulence) and the viscosity reduced with increasing temperature. The addition of inhibitors (PEB, Nano ZnO and their blends) effected Newtonian fluid behaviour in the crude samples as the shear stress-shear rate relationship curves were linear at all temperatures under study. The optimum concentration of the inhibitors in this study is 2000ppm PEB (causing 33% viscosity reduction) and 1wt% Nano ZnO (effecting 26% viscosity reduction). The best concentration of the blend was 2000ppm PEB blended with 1wt% Nano ZnO which effected a viscosity reduction of 41%. The research demonstrates the novel application of the blend of Nano ZnO and PEB in improving flowability of Nigerian waxy crude oil especially in offshore conditions with prevailing cold temperatures.
{"title":"Preventing Wax Deposition in Crude Oil Using Polyethylene Butene and Nano Zinc Oxide","authors":"Ademola Balogun, T. Odutola, Yakubu Balogun","doi":"10.2118/204317-ms","DOIUrl":"https://doi.org/10.2118/204317-ms","url":null,"abstract":"\u0000 This research examines the use of 75nm Zinc Oxide nanoparticles (Nano ZnO) and Polyethylene Butene (PEB) in reducing the viscosity of Nigerian waxy crude oil. The rheology of the crude oil was studied by measuring the viscosity and shear stress of crude samples contaminated with varying concentration of PEB (500ppm, 1000ppm, 2000ppm, 3000ppm, 4000ppm and 5000ppm), varying concentrations of Nano ZnO (1wt%, 2wt%, 3wt% and 4wt%) and different blends of PEB and Nano ZnO at temperatures of between 10°C to 35°C and shear rates from 1.7 to 1020s-1. From Rheological Modelling analysis conducted, the Power law pseudoplastic model was the best fit for the experimental data with a regression coefficient of 0.99. Analysis of crude sample before addition of inhibitor showed evidence of non-Newtonian fluid behaviour as the shear stress-shear rate relationship curves were nonlinear due to wax precipitation at low temperatures (10°C to 15°C). The waxy crude demonstrated shear thinning behaviour with increasing shear rates (increasing turbulence) and the viscosity reduced with increasing temperature. The addition of inhibitors (PEB, Nano ZnO and their blends) effected Newtonian fluid behaviour in the crude samples as the shear stress-shear rate relationship curves were linear at all temperatures under study. The optimum concentration of the inhibitors in this study is 2000ppm PEB (causing 33% viscosity reduction) and 1wt% Nano ZnO (effecting 26% viscosity reduction). The best concentration of the blend was 2000ppm PEB blended with 1wt% Nano ZnO which effected a viscosity reduction of 41%. The research demonstrates the novel application of the blend of Nano ZnO and PEB in improving flowability of Nigerian waxy crude oil especially in offshore conditions with prevailing cold temperatures.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85086095","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 recent years, the utilization of modern sampling tools provided access to the field deposits from several offshore and onshore wells producing asphaltenic crudes. Compositional analysis of field deposits revealed the presence of asphaltenes and wax as major fractions, while system conditions traditionally implied precipitation and deposition of asphaltenes only. Most of the previous studies on organic deposition have been conducted with the key assumption that aggregation and precipitation of wax and asphaltene occur independently. A few researchers investigated the solubility parameter's alteration, but they did not incorporate waxes found in the oilfield deposits. This study aims to investigate the nature of "waxphaltenes"; from intermolecular interactions between asphaltenes and wax in samples collected from fields and made in the laboratory. Asphaltenes samples were extracted and fully characterized by proton nuclear magnetic resonance (NMR) and Fourier-transform infrared spectroscopy (FTIR). Paraffin waxes were identified using gas chromatography (GC), differential scanning calorimetry (DSC), NMR, and FTIR. Precipitation tests of asphaltenes with n-heptane at high temperature were performed both in the presence and absence of wax; GC, NMR and FTIR techniques evaluated the precipitates and the material dispersed in solution. It was found that asphaltenes co-precipitated with waxes even at higher temperatures than the normal wax appearance temperature (WAT) of the crude oil or the model solutions and that long and medium size paraffin waxes had higher tendencies to coprecipitate with asphaltenes than either short chain or very long chain paraffin hydrocarbons. The results also indicated that the amount of wax that co-precipitates with asphaltenes was more related to asphaltene structure but is independent of the asphaltenes or wax content. Heteroatoms played an important role in the interactions between wax and asphaltenes during precipitation and separation.
{"title":"Uncovering Mysteries of Waxphaltenes: Meticulous Experimental Studies of Field and Lab Deposits Unveil Nature of Wax-Asphaltene Intermolecular Interactions","authors":"J. I. Aguiar, H. Samouei, A. Mahmoudkhani","doi":"10.2118/204315-ms","DOIUrl":"https://doi.org/10.2118/204315-ms","url":null,"abstract":"\u0000 In recent years, the utilization of modern sampling tools provided access to the field deposits from several offshore and onshore wells producing asphaltenic crudes. Compositional analysis of field deposits revealed the presence of asphaltenes and wax as major fractions, while system conditions traditionally implied precipitation and deposition of asphaltenes only. Most of the previous studies on organic deposition have been conducted with the key assumption that aggregation and precipitation of wax and asphaltene occur independently. A few researchers investigated the solubility parameter's alteration, but they did not incorporate waxes found in the oilfield deposits. This study aims to investigate the nature of \"waxphaltenes\"; from intermolecular interactions between asphaltenes and wax in samples collected from fields and made in the laboratory. Asphaltenes samples were extracted and fully characterized by proton nuclear magnetic resonance (NMR) and Fourier-transform infrared spectroscopy (FTIR). Paraffin waxes were identified using gas chromatography (GC), differential scanning calorimetry (DSC), NMR, and FTIR. Precipitation tests of asphaltenes with n-heptane at high temperature were performed both in the presence and absence of wax; GC, NMR and FTIR techniques evaluated the precipitates and the material dispersed in solution. It was found that asphaltenes co-precipitated with waxes even at higher temperatures than the normal wax appearance temperature (WAT) of the crude oil or the model solutions and that long and medium size paraffin waxes had higher tendencies to coprecipitate with asphaltenes than either short chain or very long chain paraffin hydrocarbons. The results also indicated that the amount of wax that co-precipitates with asphaltenes was more related to asphaltene structure but is independent of the asphaltenes or wax content. Heteroatoms played an important role in the interactions between wax and asphaltenes during precipitation and separation.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"111 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83356707","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}
S. Mohr, Felix Hoevelmann, J. Wylde, Natascha Schelero, Juan Sarria, Nirupam Purkayastha, Zachary T. Ward, Pablo Navarro Acero, Vasileios K. Michalis
Computational and experimental methods were employed to assess the capacity of four surfactant molecules to inhibit the agglomeration of sII hydrate particles. Using both steered and non-steered Molecular Dynamics (MD), the coalescence process of a hydrate slab and a water droplet, both covered with surfactant molecules, was computationally simulated. The experimental assessment was based on rocking cell measurements, determining the minimum effective dose necessary to inhibit agglomeration. Overall, the performance ranking obtained by the simulations and the experimental measurements agreed very well. Moreover, the simulations gave additional insights that are not directly accessible via experiments, such as an analysis of the mass density profiles or the orientations of the surfactant tails. The possibility to perform systematic computational high-throughput screenings of many molecules allows an efficient funnel approach for molecular optimization and customization.
{"title":"Ranking Anti-Agglomerant Efficiency for Gas Hydrates Through Molecular Dynamic Simulations","authors":"S. Mohr, Felix Hoevelmann, J. Wylde, Natascha Schelero, Juan Sarria, Nirupam Purkayastha, Zachary T. Ward, Pablo Navarro Acero, Vasileios K. Michalis","doi":"10.2118/204334-ms","DOIUrl":"https://doi.org/10.2118/204334-ms","url":null,"abstract":"\u0000 Computational and experimental methods were employed to assess the capacity of four surfactant molecules to inhibit the agglomeration of sII hydrate particles. Using both steered and non-steered Molecular Dynamics (MD), the coalescence process of a hydrate slab and a water droplet, both covered with surfactant molecules, was computationally simulated. The experimental assessment was based on rocking cell measurements, determining the minimum effective dose necessary to inhibit agglomeration. Overall, the performance ranking obtained by the simulations and the experimental measurements agreed very well. Moreover, the simulations gave additional insights that are not directly accessible via experiments, such as an analysis of the mass density profiles or the orientations of the surfactant tails. The possibility to perform systematic computational high-throughput screenings of many molecules allows an efficient funnel approach for molecular optimization and customization.","PeriodicalId":10910,"journal":{"name":"Day 2 Tue, December 07, 2021","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-11-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74968595","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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