It has been proven that scale squeezes can be conducted effectively in the unconventional, horizontal fractured wells in the shale reservoir of the Bakken when using an optimal scale squeeze chemistry. Previous work has discussed inhibitor selection and performance testing along with early case histories and modeling work. This paper discusses new case histories and Place-iT modeling results based on several procedural variations including a range of overflush volumes in the squeeze treatment procedure and the inclusion of acid cleanouts. Novel, reduced-volume squeeze designs have successfully protected wells from scale deposition while limiting the direct and indirect costs associated with extra placement water. For unconventional shale wells in the Bakken, where produced water is typically very high in TDS and TSS, fresh water is most commonly used to execute squeezes. Reducing the total water volume reduces the costs of purchasing, transporting and storing fresh water. The amount of time and cost to pump the job is decreased. Less time and money is spent lifting the placement water, and consequently, there is less deferred production. In addition, in unconventional production acid treatments are commonly carried out in isolation to maintain production. In this work, applying acidizing stages at the front of the squeeze procedures, provides a novel "squimulation" process to fractured reservoir scale control treatments. For these unconventional horizontal wells, the use of larger water volumes—either several times full wellbore volume and/or several times daily water production—has not been shown to improve the longevity or cost-effectiveness of squeeze jobs. Contrary to conventional well applications modeled with Darcy flow, it appears diffusion is the more applicable mechanism for scale inhibitor transport in fractured shale wells. This mechanism is consistent with a reduced dependence on water volume deployed in the treatments. The lessons learned from the unconventional horizontal scale squeezes conducted in the Bakken have resulted in enhanced production and cost savings. There are significant implications for the industry as other key unconventional regions in the U.S. and around the world are looking into scale squeezes as an option for scale control.
{"title":"Unconventional Horizontal Scale Squeezes: Lessons Learned Drive Continued Development and Improved Cost Savings","authors":"L. Eagle, K. Spicka, J. Fidoe, M. Jordan","doi":"10.2118/190720-MS","DOIUrl":"https://doi.org/10.2118/190720-MS","url":null,"abstract":"\u0000 It has been proven that scale squeezes can be conducted effectively in the unconventional, horizontal fractured wells in the shale reservoir of the Bakken when using an optimal scale squeeze chemistry. Previous work has discussed inhibitor selection and performance testing along with early case histories and modeling work. This paper discusses new case histories and Place-iT modeling results based on several procedural variations including a range of overflush volumes in the squeeze treatment procedure and the inclusion of acid cleanouts.\u0000 Novel, reduced-volume squeeze designs have successfully protected wells from scale deposition while limiting the direct and indirect costs associated with extra placement water. For unconventional shale wells in the Bakken, where produced water is typically very high in TDS and TSS, fresh water is most commonly used to execute squeezes. Reducing the total water volume reduces the costs of purchasing, transporting and storing fresh water. The amount of time and cost to pump the job is decreased. Less time and money is spent lifting the placement water, and consequently, there is less deferred production. In addition, in unconventional production acid treatments are commonly carried out in isolation to maintain production. In this work, applying acidizing stages at the front of the squeeze procedures, provides a novel \"squimulation\" process to fractured reservoir scale control treatments.\u0000 For these unconventional horizontal wells, the use of larger water volumes—either several times full wellbore volume and/or several times daily water production—has not been shown to improve the longevity or cost-effectiveness of squeeze jobs. Contrary to conventional well applications modeled with Darcy flow, it appears diffusion is the more applicable mechanism for scale inhibitor transport in fractured shale wells. This mechanism is consistent with a reduced dependence on water volume deployed in the treatments.\u0000 The lessons learned from the unconventional horizontal scale squeezes conducted in the Bakken have resulted in enhanced production and cost savings. There are significant implications for the industry as other key unconventional regions in the U.S. and around the world are looking into scale squeezes as an option for scale control.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128736248","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. Thornton, Yaz Belhimer, I. Smith, A. Subramaniyan
Steamflooding technology introduction into hydrocarbon recovery operations often brings with it unwanted unavoidable mineral scaling challenges. In this example, steamflood generated calcium carbonate scale caused downhole equipment failure during cyclical steamflood stimulation (CSS) operations. The precipitated scale was effectively removed via mineral acid tubing wash, however mineral acid use for ad-hoc scale dissolving duty added significantly to the corrosion burden of well production tubing strings already regularly exposed to aggressive high concentration mineral acid during near wellbore matrix stimulation treatments. Scale inhibitor squeezing was proposed as a proactive alternative to mineral acid for downhole scale mitigation, and is the subject of this case history. The Middle Eastern heavy oil (HO) field has experience in employing scale inhibitors for topside scale control, but has limited experience in scale squeezing, and no experience of scale squeezing cyclical steam flooded wells. The initiative therefore presented some interesting challenges with respect to the Scale inhibitor selection (thermal stability concerns, compatibility and calcium carbonate efficacy concerns), where to place the scale squeeze in the CSS treatment programme, the squeeze design and its placement within the CSS well, and introduction and execution of routine well scaling health monitors for assessing the performance of the scale squeeze across the full CSS life-cycle. Detailed bullheaded scale squeeze designs were prepared for two pilot HO field CSS wells that had experienced CaCO3 scaling. Once prepared, the squeeze treatments were quickly scheduled and executed without significant issue - either during treatment application or post-squeeze/steamflood return. The well brine monitors (brine ion composition, residual scale inhibitor and suspended solids) revealed interesting trends during the surveillance phase, but most importantly showed that the scale squeezes performed according to design and successfully maintained the wells free of CaCO3 scale, up to and including the 266 days post-steamflood, at which point routine well produced water sampling was discontinued. After 360 days (at the final review meeting) the field operators advised that both squeezed wells were still in operation and had experienced no scaling downtime.
{"title":"Recent Experience in Squeeze Treating Huff and Puff Wells for Control of Steamflood Generated Calcium Carbonate Scale","authors":"A. Thornton, Yaz Belhimer, I. Smith, A. Subramaniyan","doi":"10.2118/190701-MS","DOIUrl":"https://doi.org/10.2118/190701-MS","url":null,"abstract":"\u0000 Steamflooding technology introduction into hydrocarbon recovery operations often brings with it unwanted unavoidable mineral scaling challenges. In this example, steamflood generated calcium carbonate scale caused downhole equipment failure during cyclical steamflood stimulation (CSS) operations. The precipitated scale was effectively removed via mineral acid tubing wash, however mineral acid use for ad-hoc scale dissolving duty added significantly to the corrosion burden of well production tubing strings already regularly exposed to aggressive high concentration mineral acid during near wellbore matrix stimulation treatments. Scale inhibitor squeezing was proposed as a proactive alternative to mineral acid for downhole scale mitigation, and is the subject of this case history. The Middle Eastern heavy oil (HO) field has experience in employing scale inhibitors for topside scale control, but has limited experience in scale squeezing, and no experience of scale squeezing cyclical steam flooded wells. The initiative therefore presented some interesting challenges with respect to the Scale inhibitor selection (thermal stability concerns, compatibility and calcium carbonate efficacy concerns), where to place the scale squeeze in the CSS treatment programme, the squeeze design and its placement within the CSS well, and introduction and execution of routine well scaling health monitors for assessing the performance of the scale squeeze across the full CSS life-cycle.\u0000 Detailed bullheaded scale squeeze designs were prepared for two pilot HO field CSS wells that had experienced CaCO3 scaling. Once prepared, the squeeze treatments were quickly scheduled and executed without significant issue - either during treatment application or post-squeeze/steamflood return. The well brine monitors (brine ion composition, residual scale inhibitor and suspended solids) revealed interesting trends during the surveillance phase, but most importantly showed that the scale squeezes performed according to design and successfully maintained the wells free of CaCO3 scale, up to and including the 266 days post-steamflood, at which point routine well produced water sampling was discontinued. After 360 days (at the final review meeting) the field operators advised that both squeezed wells were still in operation and had experienced no scaling downtime.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"69 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114715296","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
N. Zhang, D. Schmidt, Wan-joo Choi, D. Sundararajan, Zach Reisenauer, Jack Freeman, E. Kristensen, Z. Dai, A. Kan, M. Tomson
Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to "overtreat" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.
{"title":"Halite Challenges and Mitigation in the Bakken- Experience of Managing High Saline Produced Water from Hydraulically Fractured Wells","authors":"N. Zhang, D. Schmidt, Wan-joo Choi, D. Sundararajan, Zach Reisenauer, Jack Freeman, E. Kristensen, Z. Dai, A. Kan, M. Tomson","doi":"10.2118/190739-MS","DOIUrl":"https://doi.org/10.2118/190739-MS","url":null,"abstract":"\u0000 Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to \"overtreat\" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130998410","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}
Iron sulfide deposition on downhole tubular is a ubiquitous phenomenon in sour gas wells, especially for these producing from high temperature and high pressure (HTHP) reservoirs. Many studies have been focused on iron sulfide formation and mitigation previously, the root-cause of iron sulfide deposition is still not well defined and the cost-effective scale management strategy is remained to be identified. This paper presents some new progresses made for understanding the mechanisms of iron sulfide deposition in the sour gas wells, using a combined approach of laboratorial tests and model prediction. Study results indicate that iron sulfide can deposit during both acidizing treatment and production stage. Large amount of iron sulfide could precipitate during acidizing treatment and potentially causes severe formation damage. During production stage iron sulfide is accumulated on tubular surface due to corrosion of the underlying metal. This paper presents a fundamental study to understand the mechanisms of iron sulfide deposition in sour gas wells. Corrosion and scaling inhibition are recommended to mitigate iron sulfide deposition in sour gas wells, especially during acidizing treatment.
{"title":"Mechanisms and Mitigation Strategies of Iron Sulfide Deposition in Sour Gas Wells","authors":"Tao Chen, Qiwei Wang, F. Chang","doi":"10.2118/190748-MS","DOIUrl":"https://doi.org/10.2118/190748-MS","url":null,"abstract":"\u0000 Iron sulfide deposition on downhole tubular is a ubiquitous phenomenon in sour gas wells, especially for these producing from high temperature and high pressure (HTHP) reservoirs. Many studies have been focused on iron sulfide formation and mitigation previously, the root-cause of iron sulfide deposition is still not well defined and the cost-effective scale management strategy is remained to be identified.\u0000 This paper presents some new progresses made for understanding the mechanisms of iron sulfide deposition in the sour gas wells, using a combined approach of laboratorial tests and model prediction.\u0000 Study results indicate that iron sulfide can deposit during both acidizing treatment and production stage. Large amount of iron sulfide could precipitate during acidizing treatment and potentially causes severe formation damage. During production stage iron sulfide is accumulated on tubular surface due to corrosion of the underlying metal.\u0000 This paper presents a fundamental study to understand the mechanisms of iron sulfide deposition in sour gas wells. Corrosion and scaling inhibition are recommended to mitigate iron sulfide deposition in sour gas wells, especially during acidizing treatment.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123753864","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}
Produced waters are increasingly found to contain high levels of dissolved iron, with typical ferrous iron concentrations ranging from a few ppm to several hundred ppm. The presence of iron can cause issues in production, one problem being a detrimental effect on the performance of scale inhibitors. The aim of this work was to investigate scale inhibitor chemistries with improved iron tolerance, and apply a new product in the field to address a severe inorganic scale issue that had been encountered. Using static bottle tests to assess brine compatibility and anaerobic dynamic scale loop tests to assess scale inhibition efficiency, a wide variety of scale inhibitor chemistries containing different functional groups were screened. The aim was to identify an inhibitor which would give the best performance against calcium carbonate scale in the presence of up to 100ppm Fe2+. Previous studies have shown that the inhibition of calcium carbonate scale is more adversely affected by the presence of iron than the inhibition of barium sulfate scale, and as calcium carbonate was the main challenge in the field case the emphasis was placed on inhibiting this scale type. Initial compatibility studies revealed the additives with the best brine compatibility, and around nine additives were taken forward for performance testing. It was found that acrylic acid based copolymers demonstrated reasonable scale control at 5-20 ppm Fe2+, but at higher iron the high dose levels required meant that the limit of compatibility was reached before complete scale control had been achieved. The best performing additive for calcium carbonate was found to be a phosphonate derivative. A field trial was conducted in a predominantly calcium carbonate scaling environment as a proof of concept and scale inhibitor residuals were monitored over a 5-month period. After this successful study, further lab experiments were performed with the chosen inhibitor to demonstrate good calcium carbonate control in the presence of up to 100 ppm Fe2+. A comprehensive investigation of different scale inhibitor types resulted in an optimum chemistry to control calcium carbonate scale in the presence of high concentrations of ferrous iron. Applying this chemistry in the field has demonstrated better scale control than was being achieved with the previous scale inhibitor.
{"title":"Development and Field Application of an Iron Tolerant Scale Inhibitor for use in Fracturing Completions and Production","authors":"H. Davies, M. Toole, R. Higgins","doi":"10.2118/190728-MS","DOIUrl":"https://doi.org/10.2118/190728-MS","url":null,"abstract":"\u0000 Produced waters are increasingly found to contain high levels of dissolved iron, with typical ferrous iron concentrations ranging from a few ppm to several hundred ppm. The presence of iron can cause issues in production, one problem being a detrimental effect on the performance of scale inhibitors. The aim of this work was to investigate scale inhibitor chemistries with improved iron tolerance, and apply a new product in the field to address a severe inorganic scale issue that had been encountered.\u0000 Using static bottle tests to assess brine compatibility and anaerobic dynamic scale loop tests to assess scale inhibition efficiency, a wide variety of scale inhibitor chemistries containing different functional groups were screened. The aim was to identify an inhibitor which would give the best performance against calcium carbonate scale in the presence of up to 100ppm Fe2+. Previous studies have shown that the inhibition of calcium carbonate scale is more adversely affected by the presence of iron than the inhibition of barium sulfate scale, and as calcium carbonate was the main challenge in the field case the emphasis was placed on inhibiting this scale type.\u0000 Initial compatibility studies revealed the additives with the best brine compatibility, and around nine additives were taken forward for performance testing. It was found that acrylic acid based copolymers demonstrated reasonable scale control at 5-20 ppm Fe2+, but at higher iron the high dose levels required meant that the limit of compatibility was reached before complete scale control had been achieved. The best performing additive for calcium carbonate was found to be a phosphonate derivative. A field trial was conducted in a predominantly calcium carbonate scaling environment as a proof of concept and scale inhibitor residuals were monitored over a 5-month period. After this successful study, further lab experiments were performed with the chosen inhibitor to demonstrate good calcium carbonate control in the presence of up to 100 ppm Fe2+.\u0000 A comprehensive investigation of different scale inhibitor types resulted in an optimum chemistry to control calcium carbonate scale in the presence of high concentrations of ferrous iron. Applying this chemistry in the field has demonstrated better scale control than was being achieved with the previous scale inhibitor.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124957748","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}
Scale inhibitors are commonly used for mitigating scale deposition risks in many oil and gas wells worldwide. Of the various chemistries used for scale inhibition, much research has gone into the various conditions in which each chemistry performs best (i.e. temperature, brine solubility, salinity, etc.)4-6. Furthermore, it is known that dissolved iron (Fe2+ and Fe3+) can hinder the performance of scale inhibitors, some more than others3. Thus, applying this knowledge we can extrapolate which inhibitor chemistries might perform best under a given set of conditions. This knowledge can then be applied regionally where most production comes from the same or similar reservoirs and production conditions. However, less research has been conducted on the effects of pre-existing iron sulfide deposits on the performance of scale inhibitors. Iron sulfide solids are becoming increasingly problematic in the oil field. The combination of iron sulfide with more conventional scaling deposits and the fact that scale inhibitors are surface active and tend to adsorb onto surfaces can yield very challenging situations. This paper discusses testing conducted on various scale inhibitor chemistries and evaluates how exposure to pre-existing FeS solids may impact performance. The various scale inhibitors were evaluated for inhibition performance against a set of controls (no FeS exposure) utilizing the NACE Standard TM0137-2007 "Laboratory Screening Tests to Determine the Ability of Scale Inhibitors to Prevent the Precipitation of Calcium Sulfate and Calcium Carbonate from Solution (for Oil and Gas Production Systems)" with an additional pre-test procedure to expose scale inhibitors in stock solution to a set weight of reagent grade ferrous sulfide (FeS). Scale inhibitor chemistries evaluated include two polymers (scale inhibitor A and B) and five phosphorous based scale inhibitors (scale inhibitors C through F). The various configurations tested included: scale inhibitors alone, scale inhibitor plus FeS solids, scale inhibitor without FeS plus crude oil, scale inhibitor plus FeS and crude oil. The inclusion of the crude oil allowed an interface for potential micelle interactions. The results indicate scale inhibitors A, C and G were least affected by the presence of FeS with no regard to the presence of crude oil. With this study a scale inhibitor that worked best in the presence of FeS solids for the customer's field in the Permian Basin, where FeS has become an increasing issue, was recommended. This also allowed the customer to treat the FeS solids issue via the method that works best for them.
{"title":"A Novel Evaluation of Scale Inhibitor Performance against Calcium Carbonate Scaling in the Presence of Iron Sulfide","authors":"Jeffrey Russek, Nicole Flores, Johnathon Brooks","doi":"10.2118/190723-MS","DOIUrl":"https://doi.org/10.2118/190723-MS","url":null,"abstract":"\u0000 Scale inhibitors are commonly used for mitigating scale deposition risks in many oil and gas wells worldwide. Of the various chemistries used for scale inhibition, much research has gone into the various conditions in which each chemistry performs best (i.e. temperature, brine solubility, salinity, etc.)4-6. Furthermore, it is known that dissolved iron (Fe2+ and Fe3+) can hinder the performance of scale inhibitors, some more than others3. Thus, applying this knowledge we can extrapolate which inhibitor chemistries might perform best under a given set of conditions. This knowledge can then be applied regionally where most production comes from the same or similar reservoirs and production conditions.\u0000 However, less research has been conducted on the effects of pre-existing iron sulfide deposits on the performance of scale inhibitors. Iron sulfide solids are becoming increasingly problematic in the oil field. The combination of iron sulfide with more conventional scaling deposits and the fact that scale inhibitors are surface active and tend to adsorb onto surfaces can yield very challenging situations. This paper discusses testing conducted on various scale inhibitor chemistries and evaluates how exposure to pre-existing FeS solids may impact performance. The various scale inhibitors were evaluated for inhibition performance against a set of controls (no FeS exposure) utilizing the NACE Standard TM0137-2007 \"Laboratory Screening Tests to Determine the Ability of Scale Inhibitors to Prevent the Precipitation of Calcium Sulfate and Calcium Carbonate from Solution (for Oil and Gas Production Systems)\" with an additional pre-test procedure to expose scale inhibitors in stock solution to a set weight of reagent grade ferrous sulfide (FeS).\u0000 Scale inhibitor chemistries evaluated include two polymers (scale inhibitor A and B) and five phosphorous based scale inhibitors (scale inhibitors C through F). The various configurations tested included: scale inhibitors alone, scale inhibitor plus FeS solids, scale inhibitor without FeS plus crude oil, scale inhibitor plus FeS and crude oil. The inclusion of the crude oil allowed an interface for potential micelle interactions. The results indicate scale inhibitors A, C and G were least affected by the presence of FeS with no regard to the presence of crude oil. With this study a scale inhibitor that worked best in the presence of FeS solids for the customer's field in the Permian Basin, where FeS has become an increasing issue, was recommended. This also allowed the customer to treat the FeS solids issue via the method that works best for them.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130437323","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}
Guannan Deng, A. Kan, Z. Dai, A. Lu, K. Harouaka, Yue Zhao, Xin Wang, M. Tomson
High Ca concentration up to 40,000 mg/L in produced water was observed in Marcellus shale gas wells, such extremely high concentration have great impact to solubility of sulfate scales. To evaluate this impact, the virial coefficients for Ca-SO4 ion-interaction needs to be quantified in Pitzer equation for different P-T regimes. More solubility data with high Ca concentration at high temperature (>120°C) needs to be experimentally determined. The solubility of anhydrite at Ca2+ concentration up to 1 m (mol/kg H2O) from temperature of 120°C to 220°C and at saturated vapor pressure was measured. A stainless-steel pressure proof reactor was designed to contain a Pyrex bottle, in which reagent grade anhydrite powder was mixed with salt solution of 0.25 m, 0.5 m, 0.77 m, and 1 m CaCl2. Sample was taken by using inner pressure to push solution through inline-filter, and then the Ca2+ and SO42- concentrations in the filtrate was determined by inductively coupled plasma optical emission spectrometry (ICP-OES) and compared over time to confirm when solubility equilibrium was reached. Results shows that current Pitzer's equation model (ScaleSoftPitzer 2017) predicts saturation index (SI) values with an error of less than 0.1SI at up to 0.77 m Ca2+, but shows an error as much as −0.21 SI at 1 m Ca2+ condition. For typical produced water with less than 30,000 mg/L Ca (about 0.75 m), the current model gives a reliable prediction of anhydrite solubility. If the produced water contains greater than 30,000 mg/L Ca, the model may yield error that are as much as −0.2 SI. Further experiments are needed to correct the Pitzer equation coefficients for better scale predication at higher than 30,000 mg/L Ca.
Marcellus页岩气井采出水中Ca浓度高达40000 mg/L，这种极高的浓度对硫酸盐水垢的溶解度有很大影响。为了评估这种影响，Ca-SO4离子相互作用的维里系数需要在不同的P-T制度的Pitzer方程中量化。更多的高温(bbb120℃)高Ca浓度下的溶解度数据需要通过实验来确定。测定了钙离子浓度为1 m (mol/kg H2O)时硬石膏在120 ~ 220℃和饱和蒸汽压下的溶解度。设计了一个不锈钢耐压反应器，其中装有一个耐热玻璃瓶，将试剂级硬石膏粉末与0.25 m、0.5 m、0.77 m和1 m CaCl2的盐溶液混合。利用内压推动溶液通过内联过滤器，然后用电感耦合等离子体发射光谱法(ICP-OES)测定滤液中的Ca2+和SO42-浓度，并随时间进行比较，以确定何时达到溶解度平衡。结果表明，目前的Pitzer方程模型(ScaleSoftPitzer 2017)预测饱和指数(SI)值在高达0.77 m Ca2+条件下误差小于0.1SI，但在1 m Ca2+条件下误差高达- 0.21 SI。对于Ca含量低于30,000 mg/L(约0.75 m)的典型采出水，目前的模型可以可靠地预测硬石膏的溶解度。如果采出水中Ca含量大于30,000 mg/L，则模型可能产生高达- 0.2 SI的误差。需要进一步的实验来修正Pitzer方程系数，以便在高于30,000 mg/L Ca的情况下更好地预测结垢。
{"title":"Impact of High Calcium Concentration on Sulfate Scale Prediction at High Temperature from 120°C to 220°C","authors":"Guannan Deng, A. Kan, Z. Dai, A. Lu, K. Harouaka, Yue Zhao, Xin Wang, M. Tomson","doi":"10.2118/190744-MS","DOIUrl":"https://doi.org/10.2118/190744-MS","url":null,"abstract":"\u0000 High Ca concentration up to 40,000 mg/L in produced water was observed in Marcellus shale gas wells, such extremely high concentration have great impact to solubility of sulfate scales. To evaluate this impact, the virial coefficients for Ca-SO4 ion-interaction needs to be quantified in Pitzer equation for different P-T regimes. More solubility data with high Ca concentration at high temperature (>120°C) needs to be experimentally determined.\u0000 The solubility of anhydrite at Ca2+ concentration up to 1 m (mol/kg H2O) from temperature of 120°C to 220°C and at saturated vapor pressure was measured. A stainless-steel pressure proof reactor was designed to contain a Pyrex bottle, in which reagent grade anhydrite powder was mixed with salt solution of 0.25 m, 0.5 m, 0.77 m, and 1 m CaCl2. Sample was taken by using inner pressure to push solution through inline-filter, and then the Ca2+ and SO42- concentrations in the filtrate was determined by inductively coupled plasma optical emission spectrometry (ICP-OES) and compared over time to confirm when solubility equilibrium was reached.\u0000 Results shows that current Pitzer's equation model (ScaleSoftPitzer 2017) predicts saturation index (SI) values with an error of less than 0.1SI at up to 0.77 m Ca2+, but shows an error as much as −0.21 SI at 1 m Ca2+ condition. For typical produced water with less than 30,000 mg/L Ca (about 0.75 m), the current model gives a reliable prediction of anhydrite solubility. If the produced water contains greater than 30,000 mg/L Ca, the model may yield error that are as much as −0.2 SI. Further experiments are needed to correct the Pitzer equation coefficients for better scale predication at higher than 30,000 mg/L Ca.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115634023","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}
W. Keogh, T. Charpentier, V. Eroini, J. Olsen, F. M. Nielsen, S. Baraka-Lokmane, J. Ellingsen, Oeystein Bache, A. Neville
Deposition of inorganic scale on downhole completion equipment contributes to significant downtime and loss of production within the oil and gas industry. High temperature/high pressure (HT/HP) fields have reported build-up of lead sulfide (PbS) scale as a consequence of reservoir souring. This paper reports on the design of an experimental rig allowing diffusion of H2S into a scaling brine under dynamic environments. Multiphase conditions induced by introduction of a light distillate within the system were used to create an emulsion in order to reflect more accurately the scaling process occurring within sour systems. The results showed that the presence of an oil phase within the system caused the lead sulfide nano crystals to reside at the oil- water (o/w) interface; increasing surface build-up propensity through an adhesion process. Performance of a range of coatings for potential application in oilfield environments was determined through gravimetric measurements and microscopy techniques and the wettability of surfaces was shown to have a significant influence on the degree of lead sulfide deposition in a multiphase system.
{"title":"Insights into the Mechanism of Lead Sulfide Pbs Fouling and The Influence of Light Distillate Fraction","authors":"W. Keogh, T. Charpentier, V. Eroini, J. Olsen, F. M. Nielsen, S. Baraka-Lokmane, J. Ellingsen, Oeystein Bache, A. Neville","doi":"10.2118/190731-MS","DOIUrl":"https://doi.org/10.2118/190731-MS","url":null,"abstract":"\u0000 Deposition of inorganic scale on downhole completion equipment contributes to significant downtime and loss of production within the oil and gas industry. High temperature/high pressure (HT/HP) fields have reported build-up of lead sulfide (PbS) scale as a consequence of reservoir souring. This paper reports on the design of an experimental rig allowing diffusion of H2S into a scaling brine under dynamic environments. Multiphase conditions induced by introduction of a light distillate within the system were used to create an emulsion in order to reflect more accurately the scaling process occurring within sour systems. The results showed that the presence of an oil phase within the system caused the lead sulfide nano crystals to reside at the oil- water (o/w) interface; increasing surface build-up propensity through an adhesion process. Performance of a range of coatings for potential application in oilfield environments was determined through gravimetric measurements and microscopy techniques and the wettability of surfaces was shown to have a significant influence on the degree of lead sulfide deposition in a multiphase system.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123161850","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}
K. Harouaka, Yi-Tsung Lu, G. Ruan, H. D. M. Sriyarathne, Wei Li, Guannan Deng, Yue Zhao, Xin Wang, A. Kan, M. Tomson
Calcium carbonate deposition experiments were carried out by pumping a brine solution through PTFE plastic, carbon steel, and 316 stainless steel tubing at 150°C and at a maximum SICaCO3 of 1.36. The kinetics of deposition were inferred from the variation of HCO3- concentration in the effluent with changing flow rate. The inhibition kinetics were determined before, during, and after the addition of NTMP inhibitor into the system. On the metal surfaces, deposition occurred within 10 minutes of the start of the experiment and had similar behavior with changing flow rate, whereas deposition did not begin on the PTFE surface until 30 minutes had passed. No more than 1ppm of NTMP was sufficient to completely halt deposition in the PTFE and stainless steel experiments, whereas up to 2 ppm of NTMP was required in the carbon steel experiment. The deposition kinetics were indistinguishable between the metal surfaces, and were ultimately similar on the smoother hydrophobic PTFE surface once an initial coating of scale had developed. The inhibition efficiency of the NTMP was negatively affected by the corrosion products produced in the carbon steel experiments, assumed to be primarily dissolved Fe (II). Inhibitor retention was higher in the metal surfaces than in the PTFE, possibly due to the preferential adsorption of the NTMP to the surface of the Fe rich steel tubing. Our results suggest that it is the hydrodynamics of brine in the tubing, controlled by flow rate, and the SI that are the main factors controlling scale deposition. Calcium carbonate scale attachment occurs via heterogenous nucleation directly onto the surface of the tube when the brine solution approaches oversaturation from a state of equilibrium with respect to calcium carbonate. The mechanism of inhibition in our system is likely to proceed through the formation of Ca- and Fe-NTMP complexes that either poison the growth surfaces of the scale, or drop the SI of the calcium carbonate by reducing the acitivity of free Ca in the brine.
{"title":"The Effect of Surface Material on the Mechanics of Calcium Carbonate Scale Deposition","authors":"K. Harouaka, Yi-Tsung Lu, G. Ruan, H. D. M. Sriyarathne, Wei Li, Guannan Deng, Yue Zhao, Xin Wang, A. Kan, M. Tomson","doi":"10.2118/190700-MS","DOIUrl":"https://doi.org/10.2118/190700-MS","url":null,"abstract":"\u0000 Calcium carbonate deposition experiments were carried out by pumping a brine solution through PTFE plastic, carbon steel, and 316 stainless steel tubing at 150°C and at a maximum SICaCO3 of 1.36. The kinetics of deposition were inferred from the variation of HCO3- concentration in the effluent with changing flow rate. The inhibition kinetics were determined before, during, and after the addition of NTMP inhibitor into the system. On the metal surfaces, deposition occurred within 10 minutes of the start of the experiment and had similar behavior with changing flow rate, whereas deposition did not begin on the PTFE surface until 30 minutes had passed. No more than 1ppm of NTMP was sufficient to completely halt deposition in the PTFE and stainless steel experiments, whereas up to 2 ppm of NTMP was required in the carbon steel experiment. The deposition kinetics were indistinguishable between the metal surfaces, and were ultimately similar on the smoother hydrophobic PTFE surface once an initial coating of scale had developed. The inhibition efficiency of the NTMP was negatively affected by the corrosion products produced in the carbon steel experiments, assumed to be primarily dissolved Fe (II). Inhibitor retention was higher in the metal surfaces than in the PTFE, possibly due to the preferential adsorption of the NTMP to the surface of the Fe rich steel tubing. Our results suggest that it is the hydrodynamics of brine in the tubing, controlled by flow rate, and the SI that are the main factors controlling scale deposition. Calcium carbonate scale attachment occurs via heterogenous nucleation directly onto the surface of the tube when the brine solution approaches oversaturation from a state of equilibrium with respect to calcium carbonate. The mechanism of inhibition in our system is likely to proceed through the formation of Ca- and Fe-NTMP complexes that either poison the growth surfaces of the scale, or drop the SI of the calcium carbonate by reducing the acitivity of free Ca in the brine.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128401889","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}
H. Dushanee, M. Sriyarathne, Zhang Zhang, G. Ruan, K. Harouaka, Wei Li, A. Lu, Guannan Deng, Xin Wang, Yue Zhao, A. Kan, M. Tomson
This paper discusses research on performance of scale inhibitors in the presence of ferrous ion. Iron ion is the most abundant heavy metal ion in wastewater and oilfield produced water. Fe(II) is the dominant form of iron ion in oil and gas wells due to the downhole high anoxic conditions. Fe(II) can form FeS and FeCO3 which will cause severe problems in production. Further, it is important to thoroughly investigate the inhibitor compatibility with these cations in oilfield as the existence of iron in solution effects on inhibitor chemistry. In this research, Fe(II) effect on various scale inhibitors on barite was tested using an improved anoxic testing apparatus along with laser light scattering nucleation detection method. In this newly designed apparatus strict maintenance of anoxic condition is guaranteed by constant argon flow and switch valve to transfer solution. Moreover, the high Fe(II) tolerance concentration for common inhibitors were tested by varying Fe(II) concentrations from 50-100 mg/L at 90°C and near neutral pH conditions. Most scale inhibitors show good Fe(II) tolerance at experimental conditions, while the inhibition performance of phosphonates were significantly impaired by Fe(II). It is proposed that the formation of insoluble precipitates between Fe(II) and phosphonate is very likely the reason behind the observed significant impairment. Further, two methods to reverse the detrimental effect of Fe(II) on barite scale inhibitor performance is investigated and discussed here. First, a most common organic chelating agents used in oilfield, EDTA, was tested for its ability to reverse the detrimental effect of Fe(II) on scale. Secondly, Fe(II)/Inhibitor concentration ratio was changed so that remaining inhibitor in the aqueous phase would conduct the scale inhibition.
{"title":"Evaluation of Fe(II)/Fe(III) Effect on Barite Scale Inhibitors Under Different Temperatures","authors":"H. Dushanee, M. Sriyarathne, Zhang Zhang, G. Ruan, K. Harouaka, Wei Li, A. Lu, Guannan Deng, Xin Wang, Yue Zhao, A. Kan, M. Tomson","doi":"10.2118/190735-MS","DOIUrl":"https://doi.org/10.2118/190735-MS","url":null,"abstract":"\u0000 This paper discusses research on performance of scale inhibitors in the presence of ferrous ion. Iron ion is the most abundant heavy metal ion in wastewater and oilfield produced water. Fe(II) is the dominant form of iron ion in oil and gas wells due to the downhole high anoxic conditions. Fe(II) can form FeS and FeCO3 which will cause severe problems in production. Further, it is important to thoroughly investigate the inhibitor compatibility with these cations in oilfield as the existence of iron in solution effects on inhibitor chemistry.\u0000 In this research, Fe(II) effect on various scale inhibitors on barite was tested using an improved anoxic testing apparatus along with laser light scattering nucleation detection method. In this newly designed apparatus strict maintenance of anoxic condition is guaranteed by constant argon flow and switch valve to transfer solution. Moreover, the high Fe(II) tolerance concentration for common inhibitors were tested by varying Fe(II) concentrations from 50-100 mg/L at 90°C and near neutral pH conditions. Most scale inhibitors show good Fe(II) tolerance at experimental conditions, while the inhibition performance of phosphonates were significantly impaired by Fe(II). It is proposed that the formation of insoluble precipitates between Fe(II) and phosphonate is very likely the reason behind the observed significant impairment. Further, two methods to reverse the detrimental effect of Fe(II) on barite scale inhibitor performance is investigated and discussed here. First, a most common organic chelating agents used in oilfield, EDTA, was tested for its ability to reverse the detrimental effect of Fe(II) on scale. Secondly, Fe(II)/Inhibitor concentration ratio was changed so that remaining inhibitor in the aqueous phase would conduct the scale inhibition.","PeriodicalId":445983,"journal":{"name":"Day 1 Wed, June 20, 2018","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115388095","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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