The Rajasthan Field has been undergoing waterflood with produced water reinjection (PWRI) using makeup water with a moderate sulfate (≈500 mg/L) and negligible organic content since 2010. Initial analyses of the formation water indicated that the volatile fatty acid (VFA) content was quite low (≈ 20 mg/L), suggesting a priori that the levels of H2S biogeneration and production would not be problematic. However, after less than four years the H2S production rate from the field was over 1000 kg/day and the H2S concentration in the composite separator gas was about 200 ppmv. Consequently, studies were carried out using the H2S forecasting model previously discussed in four SPE papers to determine the cause for the high level of souring and to estimate future levels and trends of H2S production in the field. The mechanistic reservoir souring model considers H2S biogeneration due to water-soluble VFAs and/or primarily oil-soluble organics such as BTEX components, the effects of H2S-siderite geochemical reactions within the reservoir to scavenge H2S, flow of H2S (and other components) through the reservoir to the surface, and partitioning of H2S into the oil, water and gas phases within the reservoir and in the surface separators. Also included in the Rajasthan model were the use of power water to lift the well production since it affects partitioning at the surface; and, the effect of chemical H2S scavengers added in selected well flowlines to maintain H2S partial pressures at safe levels. The model determined that the observed H2S production was not possible even with complete consumption of the indigenous VFAs by sulfate-reducing bacteria and that only with the majority of their organic nutrients being provided by the BTEX-type components were the historical H2S production levels able to be matched. The model results have indicated that H2S production rates have already peaked in the field, primarily due to the reduction in makeup water which provides most of the sulfate being injected into the reservoir. Sulfate is the limiting microbial reactant since the oil-soluble organic supply is essentially infinite. This study has shown even in non-seawater waterfloods and with minimal organic acids in the formation water that reservoir souring can occur, resulting in the need to handle significant levels of H2S on the surface. The significance of oil-soluble organics as a potential SRB nutrient must be considered when planning a waterflood if sulfate is injected.
{"title":"Modeling/Forecasting Reservoir Souring in a Field Rajasthan, India with an Extremely Low Indigenous Volatile Fatty Acid VFA Concentration","authors":"E. Burger, P. Venkat, Saumya H Mittal","doi":"10.2118/193636-MS","DOIUrl":"https://doi.org/10.2118/193636-MS","url":null,"abstract":"\u0000 The Rajasthan Field has been undergoing waterflood with produced water reinjection (PWRI) using makeup water with a moderate sulfate (≈500 mg/L) and negligible organic content since 2010. Initial analyses of the formation water indicated that the volatile fatty acid (VFA) content was quite low (≈ 20 mg/L), suggesting a priori that the levels of H2S biogeneration and production would not be problematic. However, after less than four years the H2S production rate from the field was over 1000 kg/day and the H2S concentration in the composite separator gas was about 200 ppmv. Consequently, studies were carried out using the H2S forecasting model previously discussed in four SPE papers to determine the cause for the high level of souring and to estimate future levels and trends of H2S production in the field.\u0000 The mechanistic reservoir souring model considers H2S biogeneration due to water-soluble VFAs and/or primarily oil-soluble organics such as BTEX components, the effects of H2S-siderite geochemical reactions within the reservoir to scavenge H2S, flow of H2S (and other components) through the reservoir to the surface, and partitioning of H2S into the oil, water and gas phases within the reservoir and in the surface separators. Also included in the Rajasthan model were the use of power water to lift the well production since it affects partitioning at the surface; and, the effect of chemical H2S scavengers added in selected well flowlines to maintain H2S partial pressures at safe levels.\u0000 The model determined that the observed H2S production was not possible even with complete consumption of the indigenous VFAs by sulfate-reducing bacteria and that only with the majority of their organic nutrients being provided by the BTEX-type components were the historical H2S production levels able to be matched. The model results have indicated that H2S production rates have already peaked in the field, primarily due to the reduction in makeup water which provides most of the sulfate being injected into the reservoir. Sulfate is the limiting microbial reactant since the oil-soluble organic supply is essentially infinite.\u0000 This study has shown even in non-seawater waterfloods and with minimal organic acids in the formation water that reservoir souring can occur, resulting in the need to handle significant levels of H2S on the surface. The significance of oil-soluble organics as a potential SRB nutrient must be considered when planning a waterflood if sulfate is injected.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83675139","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}
Propargyl alcohol, at great expense and with high toxicity, is often used as an essential synergistic component of corrosion inhibitors for acidizing; however, in our recent work, a novel indolizine derivative was found to exhibit effective protection performance without the synergism of propargyl alcohol. These indolizine derivatives were easily prepared from quinoline, pyridine, and several halide compounds via 1,3-dipolar cycloaddition reaction. The derivative could prohibit the corrosion of metal at an extremely low concentration and fulfills the requirements of increasingly stringent environmental standards. The inhibition performance of the indolizine derivatives to N80 steel was investigated in 15 wt.% HCl and 20 wt.% HCl by weight loss measurements, potentiodynamic polarization method (Tafel curves), and electrochemical impedance spectroscopy (EIS). In the absence of propargyl alcohol, when the dosage of indolizine derivatives in 15 wt.% HCl is 0.1 wt.%, the inhibition efficiency of N80 steel increases to approximately 99% at 90 °C. The indolizine derivative shows a superior anti-corrosion performance at a much lower concentration than that of benzyl quinolinium chloride (BQC, a commonly used compound in current acidizing corrosion inhibitors), which serves as the precursor to indolizine derivatives. More importantly, these protective indolizine compounds behave better than the synergistic inhibitor propargyl alcohol. The reinforced active adsorption groups in indolizine derivatives could provide extra adsorption sites and fasten the inhibitive molecule to the steel surface, thus augmenting the protective effect. Here, a new inhibitive indolizine derivative is presented as an acidizing inhibitor that may also offer a low-pollution technique for corrosion prevention.
{"title":"Insight of New Eco-Friendly Acidizing Corrosion Inhibitor: Structure and Inhibition of the Indolizine Derivatives","authors":"Zhen Yang, Yefei Wang, Renzhuo Wang, Wuhua Chen, M. Ding, Fengtao Zhan, Baofeng Hou","doi":"10.2118/193555-MS","DOIUrl":"https://doi.org/10.2118/193555-MS","url":null,"abstract":"\u0000 Propargyl alcohol, at great expense and with high toxicity, is often used as an essential synergistic component of corrosion inhibitors for acidizing; however, in our recent work, a novel indolizine derivative was found to exhibit effective protection performance without the synergism of propargyl alcohol. These indolizine derivatives were easily prepared from quinoline, pyridine, and several halide compounds via 1,3-dipolar cycloaddition reaction. The derivative could prohibit the corrosion of metal at an extremely low concentration and fulfills the requirements of increasingly stringent environmental standards. The inhibition performance of the indolizine derivatives to N80 steel was investigated in 15 wt.% HCl and 20 wt.% HCl by weight loss measurements, potentiodynamic polarization method (Tafel curves), and electrochemical impedance spectroscopy (EIS).\u0000 In the absence of propargyl alcohol, when the dosage of indolizine derivatives in 15 wt.% HCl is 0.1 wt.%, the inhibition efficiency of N80 steel increases to approximately 99% at 90 °C. The indolizine derivative shows a superior anti-corrosion performance at a much lower concentration than that of benzyl quinolinium chloride (BQC, a commonly used compound in current acidizing corrosion inhibitors), which serves as the precursor to indolizine derivatives. More importantly, these protective indolizine compounds behave better than the synergistic inhibitor propargyl alcohol. The reinforced active adsorption groups in indolizine derivatives could provide extra adsorption sites and fasten the inhibitive molecule to the steel surface, thus augmenting the protective effect. Here, a new inhibitive indolizine derivative is presented as an acidizing inhibitor that may also offer a low-pollution technique for corrosion prevention.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84086658","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, Fangfu Zhang, Yue Zhao, Guannan Deng, K. Harouaka, Xin Wang, Yi-Tsung Lu, Samiridhdi Paudyal, Saebom Ko, Shujun Gao, A. Kan, M. Tomson
Scale formation that can hinder continuous oil production is a serious problem in oilfield. Among all common scales, barite and calcite are two of the most important scales. Scale inhibitors have been widely added to prolong the induction time of scales. This study evaluates the methods and previous inhibition models to measure and predict scale formation in the presence of phosphonate and polymer inhibitors under common brine conditions. Turbidity measurement with laser light was used accurately and quickly to measure the induction time, and good reproducibility can be achieved between different sources of inhibitors. By conducting a set of independent inhibition experiments, previous models were evaluated and the demand for model improvement was carefully pointed out. On the basis of these evaluations, new ScaleSoftPizer (SSP) model was proposed by incorporating all available data under various simulated oilfield conditions (4-175°C). The new SSP barite inhibition model was more internally consistent, and the new SSP calcite inhibition model expanded the applicable temperature ranges. The new SSP model was incorporated into SSP 2019. To prove the application of new SSP model, the predicted minimum inhibitor concentrations (MICs) were compared with lab observations and field data, which shows good consistence and improvements. This study improved the prediction of MIC over wide ranges of temperature and inhibitor types, which can significantly reduce the expenses and efforts to solve scale formation problems.
{"title":"A Unified Experimental Method and Model for Predicting Scale Inhibition","authors":"Chong Dai, Z. Dai, Fangfu Zhang, Yue Zhao, Guannan Deng, K. Harouaka, Xin Wang, Yi-Tsung Lu, Samiridhdi Paudyal, Saebom Ko, Shujun Gao, A. Kan, M. Tomson","doi":"10.2118/193586-MS","DOIUrl":"https://doi.org/10.2118/193586-MS","url":null,"abstract":"\u0000 Scale formation that can hinder continuous oil production is a serious problem in oilfield. Among all common scales, barite and calcite are two of the most important scales. Scale inhibitors have been widely added to prolong the induction time of scales. This study evaluates the methods and previous inhibition models to measure and predict scale formation in the presence of phosphonate and polymer inhibitors under common brine conditions. Turbidity measurement with laser light was used accurately and quickly to measure the induction time, and good reproducibility can be achieved between different sources of inhibitors. By conducting a set of independent inhibition experiments, previous models were evaluated and the demand for model improvement was carefully pointed out. On the basis of these evaluations, new ScaleSoftPizer (SSP) model was proposed by incorporating all available data under various simulated oilfield conditions (4-175°C). The new SSP barite inhibition model was more internally consistent, and the new SSP calcite inhibition model expanded the applicable temperature ranges. The new SSP model was incorporated into SSP 2019. To prove the application of new SSP model, the predicted minimum inhibitor concentrations (MICs) were compared with lab observations and field data, which shows good consistence and improvements. This study improved the prediction of MIC over wide ranges of temperature and inhibitor types, which can significantly reduce the expenses and efforts to solve scale formation problems.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78414368","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}
Reliable estimation of organic matter characteristics is essential in drilling decisions, source rock evaluation, and unconventional reservoir production. Their measurement is based on experiments after core sampling, which is time-consuming and economically challenging. In this study, we present a new approach to evaluate the characteristics of organic matter in source and reservoir rocks by in-situ electrical heating and temperature transient analysis under in-situ conditions. The new approach is based on inverse modeling, which monitors in-situ heater temperature during electrical heating and machine learning technologies. Thermal method of electrical heating is applied for the in-situ pyrolysis, to figure out the characteristics of organic matter—kerogen volume fraction and activation energy of decomposition reaction. The heater temperature acts as an indicator of type and maturity of kerogen, since it is affected by the bulk thermal conductivity of formation, which is a function of dynamically changing rock-and-pore composition by kerogen decomposition. A full-physics simulation model of in-situ kerogen pyrolysis is used to generate output data of electrical heater temperature, which is the input data of learning-based models. Minimal simplification of physical and chemical phenomena in the full-physics simulation model, which describes the multicomponent-multiphase-nonisothermal systems involving kinetic reactions, gives the confidence of synthetic output data of heater temperature. Full-physics simulation model computes system responses under unknown and uncertain input parameters, which determine the reactivity of kerogen pyrolysis. The full-physics simulation model generates the sets of heater temperature transient data while heating with constant heat flux, in the 300 different simulated source rocks containing Types 1, 2, and 3 kerogens with various organic matter content and activation energies. Based on the set of heater temperature transient data as input parameters, Artificial Neural Network (ANN) is employed to generate a black box model to estimate the unknown organic matter content and activation energy. Developed ANN data-driven model shows better performance in estimating unknown parameters, in Types 2 and 3 kerogens with wide ranges of activation energies than Type 1 kerogen with a narrow range of activation energy. Support Vector Machines (SVM) method, which categorizes data into multiple classes by using hyperplanes, is applied to classify the heater temperature transient data into different types of kerogens and shows good performance in classification. The new characterization technology of in-situ organic matter in source rocks presented in this study provides reliable information of types and maturity of organic matter, without experiments after core sampling. It is expected to enable the realistic evaluation of source rocks under subsurface conditions, by resolving technical and economic challenges.
{"title":"Characterization of Type and Maturity of Organic Matter in Source Rock by In-situ Electrical Heating and Temperature Transient Analysis","authors":"K. Lee","doi":"10.2118/193539-MS","DOIUrl":"https://doi.org/10.2118/193539-MS","url":null,"abstract":"\u0000 Reliable estimation of organic matter characteristics is essential in drilling decisions, source rock evaluation, and unconventional reservoir production. Their measurement is based on experiments after core sampling, which is time-consuming and economically challenging. In this study, we present a new approach to evaluate the characteristics of organic matter in source and reservoir rocks by in-situ electrical heating and temperature transient analysis under in-situ conditions.\u0000 The new approach is based on inverse modeling, which monitors in-situ heater temperature during electrical heating and machine learning technologies. Thermal method of electrical heating is applied for the in-situ pyrolysis, to figure out the characteristics of organic matter—kerogen volume fraction and activation energy of decomposition reaction. The heater temperature acts as an indicator of type and maturity of kerogen, since it is affected by the bulk thermal conductivity of formation, which is a function of dynamically changing rock-and-pore composition by kerogen decomposition. A full-physics simulation model of in-situ kerogen pyrolysis is used to generate output data of electrical heater temperature, which is the input data of learning-based models. Minimal simplification of physical and chemical phenomena in the full-physics simulation model, which describes the multicomponent-multiphase-nonisothermal systems involving kinetic reactions, gives the confidence of synthetic output data of heater temperature.\u0000 Full-physics simulation model computes system responses under unknown and uncertain input parameters, which determine the reactivity of kerogen pyrolysis. The full-physics simulation model generates the sets of heater temperature transient data while heating with constant heat flux, in the 300 different simulated source rocks containing Types 1, 2, and 3 kerogens with various organic matter content and activation energies. Based on the set of heater temperature transient data as input parameters, Artificial Neural Network (ANN) is employed to generate a black box model to estimate the unknown organic matter content and activation energy. Developed ANN data-driven model shows better performance in estimating unknown parameters, in Types 2 and 3 kerogens with wide ranges of activation energies than Type 1 kerogen with a narrow range of activation energy. Support Vector Machines (SVM) method, which categorizes data into multiple classes by using hyperplanes, is applied to classify the heater temperature transient data into different types of kerogens and shows good performance in classification.\u0000 The new characterization technology of in-situ organic matter in source rocks presented in this study provides reliable information of types and maturity of organic matter, without experiments after core sampling. It is expected to enable the realistic evaluation of source rocks under subsurface conditions, by resolving technical and economic challenges.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91162603","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, H. D. M. Sriyarathne, K. Harouaka, Samridhdi Paudyal, Saebom Ko, Chong Dai, A. Lu, Guannan Deng, Xin Wang, A. Kan, M. Tomson
Silica is ubiquitous in oil and gas production water because of quartz and clay dissolution from rock formations. Furthermore, the produced water from unconventional production often contains high Ca2+, Mg2+ and Fe2+ concentrations. These common cations, especially iron, can form aqueous or surface complexes with silica and affect the nucleation inhibition of other scales such as barite. Thus, it is important to investigate the silica matrix ion effects on barite scale inhibitors efficiency to evaluate inhibitor compatibility with silica and common cations in produced waters. In this study, experimental conditions were varied from 50 mg/L to 160 mg/L SiO2 in the presence of Ca2+ (1,000 and 16,000 mg/L), Mg2+ (2,000 mg/L) and Fe2+ (10 mg/L) at 70°C and neutral pH conditions, all with a background of 1 M NaCl. Our laser scattering apparatus was used to study the effect of silica matrix ions on barite nucleation inhibition [Yan et al., 2015]. For the experiments with redox-sensitive cations (such as Fe2+), a novel anoxic apparatus along with laser scattering apparatus was used. Phosphonate, carboxylate and sulfonate inhibitors were tested. All inhibitors tolerated the experimental conditions with silica. The inhibition efficiency of phosphonate inhibitor DTPMP was impaired by high Ca2+ and Mg2+, and the addition of silica would not affect this result. The polycarboxylic acid inhibitor PPCA tolerated high Ca2+ and Mg2+ conditions, and adding silica did not have influence on this behavior. The polymeric inhibitors, such as PVS and PPCA, also tolerated the experimental conditions with Fe2+ and Fe-silica. Fe2+ significantly impaired the inhibition performance of DTPMP. This may be due to the formation of an Fe(II)-DTPMP precipitate. The detrimental effect of Fe2+ on DTPMP could be reduced, to some extent, by adding silica, which might be due to the formation of Fe-silica complex and the reduction of Fe2+ impact on phosphonate.
由于石英和粘土从岩层中溶解，二氧化硅在油气生产水中无处不在。此外，非常规开采的采出水通常含有较高的Ca2+、Mg2+和Fe2+浓度。这些常见的阳离子，尤其是铁，可以与二氧化硅形成水或表面络合物，并影响重晶石等其他尺度的成核抑制作用。因此，研究二氧化硅基质离子对重晶石阻垢剂效率的影响，以评估生产水中二氧化硅和常见阳离子对阻垢剂的相容性具有重要意义。在本研究中，实验条件从50 mg/L到160 mg/L SiO2在Ca2+(1000和16000 mg/L)、Mg2+ (2000 mg/L)和Fe2+ (10 mg/L)存在下，在70°C和中性pH条件下，均以1 M NaCl为背景。我们利用激光散射仪研究了二氧化硅基质离子对重晶石成核抑制的影响[Yan et al.， 2015]。对于氧化还原敏感阳离子(如Fe2+)的实验，采用了一种新型的缺氧装置和激光散射装置。测试了膦酸盐、羧酸盐和磺酸盐抑制剂。所有抑制剂都能耐受二氧化硅的实验条件。高Ca2+和Mg2+对膦酸盐抑制剂DTPMP的抑制效果有影响，二氧化硅的加入不影响其抑制效果。聚羧酸抑制剂PPCA耐受高Ca2+和Mg2+条件，添加二氧化硅对这种行为没有影响。聚合物抑制剂，如PVS和PPCA，也能耐受Fe2+和fe -二氧化硅的实验条件。Fe2+显著降低了DTPMP的抑制性能。这可能是由于Fe(II)-DTPMP沉淀的形成。添加二氧化硅可以在一定程度上降低Fe2+对DTPMP的有害影响，这可能是由于fe -二氧化硅配合物的形成和Fe2+对磷酸盐的影响的减少。
{"title":"Evaluation of Silica Matrix Ion Effects on Barite Scale Inhibitors","authors":"Yue Zhao, H. D. M. Sriyarathne, K. Harouaka, Samridhdi Paudyal, Saebom Ko, Chong Dai, A. Lu, Guannan Deng, Xin Wang, A. Kan, M. Tomson","doi":"10.2118/193548-MS","DOIUrl":"https://doi.org/10.2118/193548-MS","url":null,"abstract":"\u0000 Silica is ubiquitous in oil and gas production water because of quartz and clay dissolution from rock formations. Furthermore, the produced water from unconventional production often contains high Ca2+, Mg2+ and Fe2+ concentrations. These common cations, especially iron, can form aqueous or surface complexes with silica and affect the nucleation inhibition of other scales such as barite. Thus, it is important to investigate the silica matrix ion effects on barite scale inhibitors efficiency to evaluate inhibitor compatibility with silica and common cations in produced waters.\u0000 In this study, experimental conditions were varied from 50 mg/L to 160 mg/L SiO2 in the presence of Ca2+ (1,000 and 16,000 mg/L), Mg2+ (2,000 mg/L) and Fe2+ (10 mg/L) at 70°C and neutral pH conditions, all with a background of 1 M NaCl. Our laser scattering apparatus was used to study the effect of silica matrix ions on barite nucleation inhibition [Yan et al., 2015]. For the experiments with redox-sensitive cations (such as Fe2+), a novel anoxic apparatus along with laser scattering apparatus was used. Phosphonate, carboxylate and sulfonate inhibitors were tested. All inhibitors tolerated the experimental conditions with silica. The inhibition efficiency of phosphonate inhibitor DTPMP was impaired by high Ca2+ and Mg2+, and the addition of silica would not affect this result. The polycarboxylic acid inhibitor PPCA tolerated high Ca2+ and Mg2+ conditions, and adding silica did not have influence on this behavior. The polymeric inhibitors, such as PVS and PPCA, also tolerated the experimental conditions with Fe2+ and Fe-silica. Fe2+ significantly impaired the inhibition performance of DTPMP. This may be due to the formation of an Fe(II)-DTPMP precipitate. The detrimental effect of Fe2+ on DTPMP could be reduced, to some extent, by adding silica, which might be due to the formation of Fe-silica complex and the reduction of Fe2+ impact on phosphonate.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86461803","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 novel indolizine derivative inhibitor for acidization was introduced. It could exhibit effective corrosion inhibition at a much lower concentration without propargyl alcohol and shows economic and environmental advantages. From quinoline, benzyl chloride, and chloroacetic acid, two indolizine derivatives were prepared under certain conditions. These inhibitive indolizine derivatives were both synthesised from benzyl quinoline chloride (BQC), which one of the conventional quaternary ammonium corrosion inhibitors used for acidising. The target compound was purified and instrumental analysis methods including elemental analysis, high-resolution mass spectrometry (HRMS), and NMR were used to characterise the chemical structure. The inhibition performance of the indolizine derivatives in 15 wt.% HCl, 20 wt.% HCl, and mud acid (12%HCl + 3%HF) for N80 steel was investigated by weight loss measurement, electrochemical method (potentiodynamic polarization and EIS), and SEM surface morphology assessment. When 0.1 wt.% indolizine derivative was added, the inhibition efficiency of N80 steel in 15 wt.% HCl at 90 °C increased to 98.8 % and 99.1 % respectively without the synergistic effect of propargyl alcohol: however, in terms of BQC, even at a dosage of 1.0 wt.%, the inhibition efficiency of N80 steel only reached 83.3 % under the same conditions. The novel derivative could impart an improved corrosion resistance effect. Compared with BQC, there are more active adsorption sites in the derivative and therefore the inhibitor could be better fastened to the steel surface. The firmly adsorbed inhibitors would thereby prevent the metal surface from making contact with H+ ions and finally increase the inhibitory effect. As a high-efficiency corrosion inhibitor, the novel indolizine derivatives may offer a new strategy for corrosion protection in acidising.
{"title":"High-efficiency Corrosion Inhibitor for Acidizing: Synthesis, Characterization and Anti-corrosion Performance of Novel Indolizine Derivative","authors":"Yefei Wang, Zhen Yang, Renzhuo Wang, Wuhua Chen, M. Ding, Fengtao Zhan, Baofeng Hou","doi":"10.2118/193587-MS","DOIUrl":"https://doi.org/10.2118/193587-MS","url":null,"abstract":"\u0000 A novel indolizine derivative inhibitor for acidization was introduced. It could exhibit effective corrosion inhibition at a much lower concentration without propargyl alcohol and shows economic and environmental advantages. From quinoline, benzyl chloride, and chloroacetic acid, two indolizine derivatives were prepared under certain conditions. These inhibitive indolizine derivatives were both synthesised from benzyl quinoline chloride (BQC), which one of the conventional quaternary ammonium corrosion inhibitors used for acidising. The target compound was purified and instrumental analysis methods including elemental analysis, high-resolution mass spectrometry (HRMS), and NMR were used to characterise the chemical structure. The inhibition performance of the indolizine derivatives in 15 wt.% HCl, 20 wt.% HCl, and mud acid (12%HCl + 3%HF) for N80 steel was investigated by weight loss measurement, electrochemical method (potentiodynamic polarization and EIS), and SEM surface morphology assessment.\u0000 When 0.1 wt.% indolizine derivative was added, the inhibition efficiency of N80 steel in 15 wt.% HCl at 90 °C increased to 98.8 % and 99.1 % respectively without the synergistic effect of propargyl alcohol: however, in terms of BQC, even at a dosage of 1.0 wt.%, the inhibition efficiency of N80 steel only reached 83.3 % under the same conditions. The novel derivative could impart an improved corrosion resistance effect. Compared with BQC, there are more active adsorption sites in the derivative and therefore the inhibitor could be better fastened to the steel surface. The firmly adsorbed inhibitors would thereby prevent the metal surface from making contact with H+ ions and finally increase the inhibitory effect. As a high-efficiency corrosion inhibitor, the novel indolizine derivatives may offer a new strategy for corrosion protection in acidising.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80084343","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}
G. Taylor, Monica Smith-Gonzalez, J. Wylde, Antonio Pedro Oliveira
Hexahydro-1,3,5-tris(2-hydroxyethyl)-s-triazine (MEA-triazine) is by far the most ubiquitous H2S scavenger used globally and occupies at least 80% of the available oilfield market. While almost the perfect scavenger in terms of kinetics and H2S uptake, this product does suffer from a number of undesirable effects which are usually tolerated or managed by various engineering modifications. For example, pH elevation causes scaling issues, deposition of intractable polymeric solids and increased ethanolamine load in crudes entering a refinery are some of the most prominent. A new scavenging technology has been developed that offers an alternative to triazine. The guiding principles in the design of this technology were to achieve, equal or better scavenger efficiency compared to triazine, equal or better reaction kinetics compared to triazine, "best in class" solids control, minimal pH impact, cost competitive with triazine, no impact on fluid separation and minimal refinery impact. A family of products have been developed which are multicomponent systems, each having a designated function. The active scavenger is based upon a "latent" or hidden form of a small molecule scavenger (SMS), similar to a protecting group strategy in organic synthesis. The steady state active SMS concentration remains very low in the initial product, but it is released upon demand when it encounters hydrogen sulfide in its operational environment. The SMS release can be greatly enhanced using a suitable catalyst or synergist, over the base scavenger/carrier system, which enables a more efficient use of the base molecule. The quality and exact nature of the spent fluid is critically important to H2S scavengers and much effort has gone into the control and handling of the byproduct. High sulfur scavenger byproducts are almost always solid in nature and can cause numerous operational issues. MEA triazine has such a problem and polymerization of the initially formed monomeric dithiazine to amorphous dithiazine is one of the drivers to develop an alternative as is presented here. This new suite of products has undergone successful field trials in both gas contact towers and direct injection applications. Some challenges have also arisen, as expected with any innovation, in other application areas and environments where unexpected issues have been encountered. An honest and informative account of the design, development, properties, field trial results and future direction for this exciting new technology are discussed as well as a critical evaluation against the aforementioned triazine industry benchmark.
{"title":"H2S Scavenger Development During the Oil and Gas Industry Search for an MEA Triazine Replacement in Hydrogen Sulfide Mitigation and Enhanced Monitoring Techniques Employed During Their Evaluation","authors":"G. Taylor, Monica Smith-Gonzalez, J. Wylde, Antonio Pedro Oliveira","doi":"10.2118/193536-MS","DOIUrl":"https://doi.org/10.2118/193536-MS","url":null,"abstract":"Hexahydro-1,3,5-tris(2-hydroxyethyl)-s-triazine (MEA-triazine) is by far the most ubiquitous H2S scavenger used globally and occupies at least 80% of the available oilfield market. While almost the perfect scavenger in terms of kinetics and H2S uptake, this product does suffer from a number of undesirable effects which are usually tolerated or managed by various engineering modifications. For example, pH elevation causes scaling issues, deposition of intractable polymeric solids and increased ethanolamine load in crudes entering a refinery are some of the most prominent.\u0000 A new scavenging technology has been developed that offers an alternative to triazine. The guiding principles in the design of this technology were to achieve, equal or better scavenger efficiency compared to triazine, equal or better reaction kinetics compared to triazine, \"best in class\" solids control, minimal pH impact, cost competitive with triazine, no impact on fluid separation and minimal refinery impact. A family of products have been developed which are multicomponent systems, each having a designated function. The active scavenger is based upon a \"latent\" or hidden form of a small molecule scavenger (SMS), similar to a protecting group strategy in organic synthesis. The steady state active SMS concentration remains very low in the initial product, but it is released upon demand when it encounters hydrogen sulfide in its operational environment. The SMS release can be greatly enhanced using a suitable catalyst or synergist, over the base scavenger/carrier system, which enables a more efficient use of the base molecule. The quality and exact nature of the spent fluid is critically important to H2S scavengers and much effort has gone into the control and handling of the byproduct. High sulfur scavenger byproducts are almost always solid in nature and can cause numerous operational issues. MEA triazine has such a problem and polymerization of the initially formed monomeric dithiazine to amorphous dithiazine is one of the drivers to develop an alternative as is presented here.\u0000 This new suite of products has undergone successful field trials in both gas contact towers and direct injection applications. Some challenges have also arisen, as expected with any innovation, in other application areas and environments where unexpected issues have been encountered. An honest and informative account of the design, development, properties, field trial results and future direction for this exciting new technology are discussed as well as a critical evaluation against the aforementioned triazine industry benchmark.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85459882","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}
Zhang Jie, Xianguang Xu, Lihui Wang, Li Long, Zhang Die, Zhao Zhiliang, S. Wang
Severe formation damage is induced by the invasion of working fluid and the subsequent water blocking. Surface modification by surfactant adsorption can change the wettability of the rock surface to enhance the removal efficiency of reservoir fluid and reduce the water blockage damage. Therefore, surfactant shows a good potential applicant in condense reservoir. In the current paper, an oligomeric silicone surfactant (OSSF) containing sulfonic acid groups is synthesized to improve the water flowback effect. The critical micelle concentration (CMC) is determined by equilibrium surface tension. Micelle can be formed above the CMC and its size and distribution increase with the concentration. At the same time, the surface tension increases with the aging temperature but decreases with the adding of inorganic salt. The OSSF adsorption through solid-liquid surface can change the surface chemical composition and transfer the wettability of reservoir from water-wet to gas-wet by decreasing the surface energy. Increasing temperature leads to the change in the adsorption isotherm from Langmuir type (L-type) to "double plateau" type (LS- type). Quantum chemistry study shows that the adsorbed layer of OSSF can reduce the adhesive force of CH4 and H2O on the pore surface of cores. The OSSF can also decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS). It is found that the surface tension of OSSF increases with aging temperature but decreases with the adding of inorganic salts.The OSSF has positive effect on wettability reversal to water-wet reservoir by adsorption on solid-liquid interface. The results indicate OSSF adsorption layer can change surface chemical composition and exhibit lower interface energy than that of the cores. The presence of NaCl can decrease foaming volume and improve foam stability of OSSF. At the same time, OSSF can decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
{"title":"Experimental Study on the Synthesis and Interfacial Properties of Oligomeric Silicone Surfactant","authors":"Zhang Jie, Xianguang Xu, Lihui Wang, Li Long, Zhang Die, Zhao Zhiliang, S. Wang","doi":"10.2118/193625-MS","DOIUrl":"https://doi.org/10.2118/193625-MS","url":null,"abstract":"\u0000 Severe formation damage is induced by the invasion of working fluid and the subsequent water blocking. Surface modification by surfactant adsorption can change the wettability of the rock surface to enhance the removal efficiency of reservoir fluid and reduce the water blockage damage. Therefore, surfactant shows a good potential applicant in condense reservoir. In the current paper, an oligomeric silicone surfactant (OSSF) containing sulfonic acid groups is synthesized to improve the water flowback effect.\u0000 The critical micelle concentration (CMC) is determined by equilibrium surface tension. Micelle can be formed above the CMC and its size and distribution increase with the concentration. At the same time, the surface tension increases with the aging temperature but decreases with the adding of inorganic salt. The OSSF adsorption through solid-liquid surface can change the surface chemical composition and transfer the wettability of reservoir from water-wet to gas-wet by decreasing the surface energy. Increasing temperature leads to the change in the adsorption isotherm from Langmuir type (L-type) to \"double plateau\" type (LS- type). Quantum chemistry study shows that the adsorbed layer of OSSF can reduce the adhesive force of CH4 and H2O on the pore surface of cores. The OSSF can also decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).\u0000 It is found that the surface tension of OSSF increases with aging temperature but decreases with the adding of inorganic salts.The OSSF has positive effect on wettability reversal to water-wet reservoir by adsorption on solid-liquid interface. The results indicate OSSF adsorption layer can change surface chemical composition and exhibit lower interface energy than that of the cores. The presence of NaCl can decrease foaming volume and improve foam stability of OSSF. At the same time, OSSF can decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87282479","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}
With the current applications of CO2 in oil wells for enhanced oil recovery (EOR) and sequestration purposes, the dissolution of CO2 in the formation brine and the formation of carbonic acid is a major cause of cement damage. This degradation can lead to non-compliance with the functions of the cement as it changes compressive and shear bond strengths and porosity and permeability of cement. It becomes imperative to understand the degradation mechanism of cement and methods to reduce the damage such as the addition of special additives to improve the resistance of cement against acid attack. Hence, the primary objective of this study is to investigate the effects of hydroxyapatite on cement degradation. To investigate the impacts of hydroxyapatite additive on oil well cement performance, two Class H cement slurry formulations (baseline/HS and hydroxyapatite containing cement/HHO) were compared after exposure to acidic environments. To evaluate the performance of the formulations, samples were prepared and aged in high-pressure high-temperature (HPHT) autoclave containing 2% brine saturated with mixed gas containing methane and carbon dioxide. Tests were performed at different temperatures (38 to 221°C), pressures (21 to 63 MPa) and CO2 concentrations (10 to 100%). After aging for 14 days at constant pressure and temperature, the samples were recovered and their bond and compressive strength, porosity and permeability were measured and compared with those of unaged samples. The results demonstrated that adding hydroxyapatite limits carbonation. Baseline samples that do not contain hydroxyapatite carbonated and consequently their compressive strength, porosity, permeability, and shear bond strength significantly changed after aging while hydroxyapatite-containing samples displayed a limited change in their properties. However, hydroxyapatite-containing samples exhibit high permeability due to the formation of microcracks after exposure to carbonic acid at high temperature (221°C). The formation of microcracks could be attributed to thermal retrogression or other phenomena that cause the expansion of the cement. This article sheds light on the application of hydroxyapatite as a cement additive to improve the carbonic acid resistance of oil well cement. It presents hydroxyapatite containing cement formulation that has acceptable slurry properties for field applications and better carbonic acid resistance compared to conventional cement.
{"title":"Carbonic Acid Resistance of Hydroxyapatite Based Cement","authors":"Aman Srivastava, R. Ahmed, Subhash N. Shah","doi":"10.2118/193585-MS","DOIUrl":"https://doi.org/10.2118/193585-MS","url":null,"abstract":"\u0000 With the current applications of CO2 in oil wells for enhanced oil recovery (EOR) and sequestration purposes, the dissolution of CO2 in the formation brine and the formation of carbonic acid is a major cause of cement damage. This degradation can lead to non-compliance with the functions of the cement as it changes compressive and shear bond strengths and porosity and permeability of cement. It becomes imperative to understand the degradation mechanism of cement and methods to reduce the damage such as the addition of special additives to improve the resistance of cement against acid attack. Hence, the primary objective of this study is to investigate the effects of hydroxyapatite on cement degradation.\u0000 To investigate the impacts of hydroxyapatite additive on oil well cement performance, two Class H cement slurry formulations (baseline/HS and hydroxyapatite containing cement/HHO) were compared after exposure to acidic environments. To evaluate the performance of the formulations, samples were prepared and aged in high-pressure high-temperature (HPHT) autoclave containing 2% brine saturated with mixed gas containing methane and carbon dioxide. Tests were performed at different temperatures (38 to 221°C), pressures (21 to 63 MPa) and CO2 concentrations (10 to 100%). After aging for 14 days at constant pressure and temperature, the samples were recovered and their bond and compressive strength, porosity and permeability were measured and compared with those of unaged samples.\u0000 The results demonstrated that adding hydroxyapatite limits carbonation. Baseline samples that do not contain hydroxyapatite carbonated and consequently their compressive strength, porosity, permeability, and shear bond strength significantly changed after aging while hydroxyapatite-containing samples displayed a limited change in their properties. However, hydroxyapatite-containing samples exhibit high permeability due to the formation of microcracks after exposure to carbonic acid at high temperature (221°C). The formation of microcracks could be attributed to thermal retrogression or other phenomena that cause the expansion of the cement.\u0000 This article sheds light on the application of hydroxyapatite as a cement additive to improve the carbonic acid resistance of oil well cement. It presents hydroxyapatite containing cement formulation that has acceptable slurry properties for field applications and better carbonic acid resistance compared to conventional cement.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85572453","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}
Production from highly paraffinic crude oil wells poses unique technical challenges such as poor flowability and paraffin deposition on the production tubing. Paraffin deposition increases the lift load on the pump, reduces pump efficiency, and eventually plugs the pump. To restore the productivity of these wells a common solution is to inject hot oil or hot water at 160°F–200°F to clean the deposits. This process imposes higher operating cost and lost production due to well downtime. Paraffin inhibitor (PI) and pour point depressant (PPD) have been used to treat paraffinic fluids but are not effective for wells with high water cuts. These wells when treated with PI/PPD still require high cost maintenance such as the hot oil/water jobs and/or well workover. This paper presents a more effective treatment using tailored chemical mixtures to form a water dispersion with the paraffinic oil, thus to increase oil flowability and reduce deposition. A novel test method has been developed to evaluate effectiveness of treatment chemicals on various paraffinic oils based on flowability and cleanliness. The test method has been validated with field trial data from three different wells in the Uinta Basin, Utah and Julesburg Basin, Colorado. The results of the field trials showed a significant increase in pumping efficiency and crude oil production. Need for hot water application was also reduced or eliminated for the treated wells. Improved oil and produced water quality were also observed. These results demonstrated that the water dispersion-based treatment is a more effective treatment for high paraffin wells with high water cuts.
{"title":"A More Effective Solution to Treat Paraffinic Crude Oil Wells","authors":"T. Phan, M. Faust, V. Balsamo, Nalco Champion","doi":"10.2118/193591-MS","DOIUrl":"https://doi.org/10.2118/193591-MS","url":null,"abstract":"\u0000 Production from highly paraffinic crude oil wells poses unique technical challenges such as poor flowability and paraffin deposition on the production tubing. Paraffin deposition increases the lift load on the pump, reduces pump efficiency, and eventually plugs the pump. To restore the productivity of these wells a common solution is to inject hot oil or hot water at 160°F–200°F to clean the deposits. This process imposes higher operating cost and lost production due to well downtime.\u0000 Paraffin inhibitor (PI) and pour point depressant (PPD) have been used to treat paraffinic fluids but are not effective for wells with high water cuts. These wells when treated with PI/PPD still require high cost maintenance such as the hot oil/water jobs and/or well workover. This paper presents a more effective treatment using tailored chemical mixtures to form a water dispersion with the paraffinic oil, thus to increase oil flowability and reduce deposition. A novel test method has been developed to evaluate effectiveness of treatment chemicals on various paraffinic oils based on flowability and cleanliness. The test method has been validated with field trial data from three different wells in the Uinta Basin, Utah and Julesburg Basin, Colorado.\u0000 The results of the field trials showed a significant increase in pumping efficiency and crude oil production. Need for hot water application was also reduced or eliminated for the treated wells. Improved oil and produced water quality were also observed. These results demonstrated that the water dispersion-based treatment is a more effective treatment for high paraffin wells with high water cuts.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83649249","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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