Halite precipitation from gas reservoir brines can cause significant decreases in hydrocarbon production or even complete blockage of the well. This has led to many gas wells either producing at diminished rates or being abandoned. Production decline related to halite scale is routinely treated with water washes either in a continuous system or with "mini squeezes" where water is batched in and held for few hours before production resumes usually with increased pressure. Introduction of halite inhibitors as part of the water wash or squeeze treatment has contributed to increased production by reducing the frequency and quantity of water used for treatment. This paper summarizes the work performed to deliver to the industry a high-temperature, high-performance halite scale inhibitor. The product chemistry offers a true step-change in performance from existing technologies because of its high-temperature stability and halite inhibition efficiency at 420°F (bottom-hole temperature). An industry best-in-class rapid screening technique (kinetic turbidity test) was used to systematically evaluate all current technologies in the market place and to develop a detailed understanding on structure-performance relationships of functional groups. The resulting correlations led to synthesis of novel high-temperature stable chemistries with significantly superior inhibition on halite. This paper also presents field cases of halite squeeze treatments from two different fields; an ultra hot (420°F) deep (17,460ft) dolomite gas well with severe halite deposition that required water washing every 48-72 hours and a shallow (6,000ft) hot (250°F) shale with erratic production where several water washes, work-overs and varied shut in periods did little to improve production. The ultra hot, deep well case history comes from a field in Texas where a detailed program of work was undertaken that led to squeezing in the halite inhibitor. Halite deposition had forced the operator to reduce production rates, with frequent workover to treat the well mainly with fresh water washes every 48 to 72 hours. After the introduction of the halite inhibitor, the gas well had been continuously producing for 40 days at the first instance and 60 days when the halite inhibitor dosage was increased. This is a marked improvement for the well and saves significant operating cost from well entries and deferred/lost production. The paper describes a detailed methodology of halite inhibitor selection and the influence that temperature, pressure and salinity has upon application. Field application case histories share important lesson learned with regards to water washing volumes (small and large water washes) as well as the impact of extended shut in period on squeeze lifetime. These squeeze treatments provide valuable field insights to salt formation and prevention in gas wells and the use of the novel high-temperature inhibitor shows a new industry capability of inhibiting halite formation
{"title":"Establishing Stable Gas Production by Squeezing a Novel Halite Inhibitor into High Temperature Texas Gas Wells","authors":"C. Okocha, Suyung Wang, A. Kaiser, J. Wylde","doi":"10.2118/190736-MS","DOIUrl":"https://doi.org/10.2118/190736-MS","url":null,"abstract":"\u0000 Halite precipitation from gas reservoir brines can cause significant decreases in hydrocarbon production or even complete blockage of the well. This has led to many gas wells either producing at diminished rates or being abandoned. Production decline related to halite scale is routinely treated with water washes either in a continuous system or with \"mini squeezes\" where water is batched in and held for few hours before production resumes usually with increased pressure. Introduction of halite inhibitors as part of the water wash or squeeze treatment has contributed to increased production by reducing the frequency and quantity of water used for treatment.\u0000 This paper summarizes the work performed to deliver to the industry a high-temperature, high-performance halite scale inhibitor. The product chemistry offers a true step-change in performance from existing technologies because of its high-temperature stability and halite inhibition efficiency at 420°F (bottom-hole temperature). An industry best-in-class rapid screening technique (kinetic turbidity test) was used to systematically evaluate all current technologies in the market place and to develop a detailed understanding on structure-performance relationships of functional groups. The resulting correlations led to synthesis of novel high-temperature stable chemistries with significantly superior inhibition on halite.\u0000 This paper also presents field cases of halite squeeze treatments from two different fields; an ultra hot (420°F) deep (17,460ft) dolomite gas well with severe halite deposition that required water washing every 48-72 hours and a shallow (6,000ft) hot (250°F) shale with erratic production where several water washes, work-overs and varied shut in periods did little to improve production. The ultra hot, deep well case history comes from a field in Texas where a detailed program of work was undertaken that led to squeezing in the halite inhibitor. Halite deposition had forced the operator to reduce production rates, with frequent workover to treat the well mainly with fresh water washes every 48 to 72 hours. After the introduction of the halite inhibitor, the gas well had been continuously producing for 40 days at the first instance and 60 days when the halite inhibitor dosage was increased. This is a marked improvement for the well and saves significant operating cost from well entries and deferred/lost production.\u0000 The paper describes a detailed methodology of halite inhibitor selection and the influence that temperature, pressure and salinity has upon application. Field application case histories share important lesson learned with regards to water washing volumes (small and large water washes) as well as the impact of extended shut in period on squeeze lifetime. These squeeze treatments provide valuable field insights to salt formation and prevention in gas wells and the use of the novel high-temperature inhibitor shows a new industry capability of inhibiting halite formation","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82668304","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}
Understanding the reservoir connectivity advances engineering and management decisions and enhances overall field performance. A method to investigate injector to producer connectivity from an identified proportion of the injected brine in the produced water is proposed. Chloride, sodium, boron and lithium are ideal tracers: typically they do not participate in geochemical reactions. These ions track injection water without retardation, and if their concentration differences with formation brine are high enough to overcome measurement errors, then they may be used as indicators of the mixing ratio between injection and formation brines. This paper proposes the use of this mixing ratio to distinguish brines and to calculate the normalised contribution of injected water in the cumulative produced water volume. A producer to injector connectivity plot allows engineers to categorise the pressure support for production wells in one plot. This approach was applied to North Sea field data. A mineral scaling risk analysis was performed using the Injector Contribution characteristic plot. Wells being supported by commingled injected seawater and aquifer water were most at risk of BaSO4 precipitation. Historic data for a field case were analysed to examine potential scaling regimes. A set of well candidates for enhanced oil recovery to reduce residual oil in the oil leg was also identified. Most of the water produced in these wells came from injectors, rather than from the aquifer. Those wells have good communication throughout the oil leg and as a result quick water breakthrough occurs. As well as resulting in an early onset of BaSO4 scaling, an Enhanced Oil Recovery (EOR) chemical that is injected would more quickly reach the producers and therefore the potential for chemical EOR applications can be measured. This suggested metric helps to identify that other wells do not experience much seawater production, but are more strongly supported by the aquifer, and so there would be no apparent benefit in reducing residual oil by injecting chemical. This set of wells might benefit potentially from infill drilling nearby, or conformance control methods. The proposed technique does not require additional sampling to be performed over and above the measured historical produced water compositions that are routinely collected by operators during offshore production for scale management purposes. The analysis to select well candidates for EOR or areas for infill drilling is significantly more challenging using a conventional approach, and we propose that this novel metric of "Producer to Injector connectivity" will be beneficial for the decision making process.
{"title":"Extending Reservoir Knowledge from the Produced Data","authors":"Oleg Ishkov, E. Mackay","doi":"10.2118/190753-MS","DOIUrl":"https://doi.org/10.2118/190753-MS","url":null,"abstract":"\u0000 Understanding the reservoir connectivity advances engineering and management decisions and enhances overall field performance. A method to investigate injector to producer connectivity from an identified proportion of the injected brine in the produced water is proposed.\u0000 Chloride, sodium, boron and lithium are ideal tracers: typically they do not participate in geochemical reactions. These ions track injection water without retardation, and if their concentration differences with formation brine are high enough to overcome measurement errors, then they may be used as indicators of the mixing ratio between injection and formation brines. This paper proposes the use of this mixing ratio to distinguish brines and to calculate the normalised contribution of injected water in the cumulative produced water volume. A producer to injector connectivity plot allows engineers to categorise the pressure support for production wells in one plot.\u0000 This approach was applied to North Sea field data. A mineral scaling risk analysis was performed using the Injector Contribution characteristic plot. Wells being supported by commingled injected seawater and aquifer water were most at risk of BaSO4 precipitation. Historic data for a field case were analysed to examine potential scaling regimes. A set of well candidates for enhanced oil recovery to reduce residual oil in the oil leg was also identified. Most of the water produced in these wells came from injectors, rather than from the aquifer. Those wells have good communication throughout the oil leg and as a result quick water breakthrough occurs. As well as resulting in an early onset of BaSO4 scaling, an Enhanced Oil Recovery (EOR) chemical that is injected would more quickly reach the producers and therefore the potential for chemical EOR applications can be measured. This suggested metric helps to identify that other wells do not experience much seawater production, but are more strongly supported by the aquifer, and so there would be no apparent benefit in reducing residual oil by injecting chemical. This set of wells might benefit potentially from infill drilling nearby, or conformance control methods.\u0000 The proposed technique does not require additional sampling to be performed over and above the measured historical produced water compositions that are routinely collected by operators during offshore production for scale management purposes. The analysis to select well candidates for EOR or areas for infill drilling is significantly more challenging using a conventional approach, and we propose that this novel metric of \"Producer to Injector connectivity\" will be beneficial for the decision making process.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89327572","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 deposition in oilfield production systems is influenced by thermodynamic supersaturation and kinetics, but also by hydrodynamic effects such as surface shear stress and turbulence. Results from experimental work investigating the impact of these hydrodynamic factors on scale location and correlating them to field flow regimes are presented. Laboratory tests have been conducted using both a benchtop jet impingement method and large-scale, high flow rate "pilot rig" apparatus. Both of these systems result in high shear stress conditions and can simulate hydrodynamic regimes representative of those expected in devices such as inflow control valves, inflow control devices, and sand control screens. The pilot rig is able to reproduce field-representative flow rates and fluid flow dynamics through full-size test pieces containing nozzles and restrictions. The results of this work demonstrate that the hydrodynamic regime has a significant influence on scale deposition. Increased levels of surface shear stress and turbulence result in a greater potential for scale formation than low shear, laminar flow conditions. This is particularly apparent in systems which are mildly supersaturated. The location of scale deposits was found to correlate with local shear stress and the pilot rig tests confirmed field observations that zones experiencing the highest level of shear are not necessarily those with the greatest deposit; the induced scale may deposit downstream in areas of lower surface shear. Additionally, the presence of these high shear locations upstream of the lower shear regime may lead to scaling in the lower shear region which would otherwise not be experienced. Supportive Computational Fluid Dynamic modelling of fluid flow within the pilot rig system correlated with the experimental findings is also described. This work allows a greater understanding of the hydrodynamic factors, in particular surface shear stress, influence oilfield scale deposition and has demonstrated the utility of both benchtop and pilot-scale methods for testing under appropriate conditions.
{"title":"Scale Deposition and Hydrodynamics - Benchtop to Pilot Rig","authors":"N. Goodwin, M. May, D. Nichols, G. Graham","doi":"10.2118/190756-MS","DOIUrl":"https://doi.org/10.2118/190756-MS","url":null,"abstract":"\u0000 Scale deposition in oilfield production systems is influenced by thermodynamic supersaturation and kinetics, but also by hydrodynamic effects such as surface shear stress and turbulence. Results from experimental work investigating the impact of these hydrodynamic factors on scale location and correlating them to field flow regimes are presented.\u0000 Laboratory tests have been conducted using both a benchtop jet impingement method and large-scale, high flow rate \"pilot rig\" apparatus. Both of these systems result in high shear stress conditions and can simulate hydrodynamic regimes representative of those expected in devices such as inflow control valves, inflow control devices, and sand control screens. The pilot rig is able to reproduce field-representative flow rates and fluid flow dynamics through full-size test pieces containing nozzles and restrictions.\u0000 The results of this work demonstrate that the hydrodynamic regime has a significant influence on scale deposition. Increased levels of surface shear stress and turbulence result in a greater potential for scale formation than low shear, laminar flow conditions. This is particularly apparent in systems which are mildly supersaturated. The location of scale deposits was found to correlate with local shear stress and the pilot rig tests confirmed field observations that zones experiencing the highest level of shear are not necessarily those with the greatest deposit; the induced scale may deposit downstream in areas of lower surface shear. Additionally, the presence of these high shear locations upstream of the lower shear regime may lead to scaling in the lower shear region which would otherwise not be experienced. Supportive Computational Fluid Dynamic modelling of fluid flow within the pilot rig system correlated with the experimental findings is also described.\u0000 This work allows a greater understanding of the hydrodynamic factors, in particular surface shear stress, influence oilfield scale deposition and has demonstrated the utility of both benchtop and pilot-scale methods for testing under appropriate conditions.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85227540","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Hosseini, E. Joonaki, J. Buckman, B. Ruggeri, B. Tohidi
Inorganic scale deposition is one of the most serious flow assurance problems. One of these exotic scales is halite (NaCl). Injection of hydrate inhibitors (HIs) [methanol, monoethylene glycol (MEG), triethylene glycol (TEG)] to prevent plugging of flow lines and tubing could induce precipitation of halite scales. Thus, utilizing these chemicals might adversely affect salt solubility, causing scaling problems, particularly halite scales, in high total dissolved solid (TDS) brines. In this study, the influence of HIs on scaling of a supersaturated NaCl solution with and without inhibitor was experimentally investigated. The results of these experiments show that increasing the concentration of HIs results in a higher amount of halite precipitation. Moreover, the effect of methanol on halite precipitation is more severe compared to MEG and TEG. On the other hand, the static efficiency results illustrate that raising the concentration of HI reduces the scale inhibition efficiency in the presence of methanol and TEG to a lower extent, while the inhibitor could have a 100% inhibition efficiency in the MEG solution. Furthermore, in the case of methanol, the optimum inhibition efficiencies at HI concentrations of 10 and 40 wt% were observed at SI concentrations of 500 and 200 ppm, respectively. Alterations in the morphology of halite in the presence of HIs were analyzed using optical microscopy and environmental scanning electron microscopy (ESEM) techniques. In this study, the effect of morphology changes of halite due to the addition of HI is addressed for the first time. These investigations can help provide a better understanding of the mechanism of halite scaling in the presence of HIs.
{"title":"Impact of Gas Hydrate Inhibitors on Halite Scale Precipitation: An Experimental and Morphological Investigation","authors":"S. Hosseini, E. Joonaki, J. Buckman, B. Ruggeri, B. Tohidi","doi":"10.2118/190707-MS","DOIUrl":"https://doi.org/10.2118/190707-MS","url":null,"abstract":"\u0000 Inorganic scale deposition is one of the most serious flow assurance problems. One of these exotic scales is halite (NaCl). Injection of hydrate inhibitors (HIs) [methanol, monoethylene glycol (MEG), triethylene glycol (TEG)] to prevent plugging of flow lines and tubing could induce precipitation of halite scales. Thus, utilizing these chemicals might adversely affect salt solubility, causing scaling problems, particularly halite scales, in high total dissolved solid (TDS) brines. In this study, the influence of HIs on scaling of a supersaturated NaCl solution with and without inhibitor was experimentally investigated.\u0000 The results of these experiments show that increasing the concentration of HIs results in a higher amount of halite precipitation. Moreover, the effect of methanol on halite precipitation is more severe compared to MEG and TEG. On the other hand, the static efficiency results illustrate that raising the concentration of HI reduces the scale inhibition efficiency in the presence of methanol and TEG to a lower extent, while the inhibitor could have a 100% inhibition efficiency in the MEG solution. Furthermore, in the case of methanol, the optimum inhibition efficiencies at HI concentrations of 10 and 40 wt% were observed at SI concentrations of 500 and 200 ppm, respectively. Alterations in the morphology of halite in the presence of HIs were analyzed using optical microscopy and environmental scanning electron microscopy (ESEM) techniques. In this study, the effect of morphology changes of halite due to the addition of HI is addressed for the first time. These investigations can help provide a better understanding of the mechanism of halite scaling in the presence of HIs.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82651565","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}
Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed. This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine. Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft. prior to the start of LSSW/PW/SW injection. Highly scaling brine has been injected now for 16 months into the thirteen wells at an average rate of 25,000 BWPD per well with no decline in injector performance observed. The lessons learned from this study are that changes in scaling potential within a PWRI system can be controlled by carrying out an assessment of location of scale formation and adoption of more typical production well scale squeezes treatment technology to protect the critical near wellbore region around PWRI injection wells.
{"title":"Management of Scale Control in Produced Water Reinjection - The Near Wellbore Scale Challenge Overcome","authors":"M. Jordan","doi":"10.2118/190713-MS","DOIUrl":"https://doi.org/10.2118/190713-MS","url":null,"abstract":"\u0000 Formation of sulphate and carbonate scale is well understood within the hydrocarbon extraction industry with injection of incompatible water such as seawater into reservoir with significant concentration of barium, strontium and calcium. To overcome this challenge chemical inhibition has been utilized for many decades and in the past 15 years elimination/reduction of the sulphate ion source from injection seawater using sulphate reduction membranes has been employed.\u0000 This paper present laboratory work to qualify a scale inhibitor and field results of its application to prevent scale formation when an operator had to change from low sulphate seawater (LSSW) mixed with produced water (PW) for their water injection source to a blend of LSSW/PW and full sulphate seawater (SW). The increased level of sulphate presented a significant scale risk within the topside process on fluid mixing but more significantly increased the risk of scale formation within the near wellbore region of the injector wells which were under matrix injection rather than fracture flow regime. The qualification of a suitable inhibitor required assessment of the retention of a potentially suitable vinyl sulphonate co polymer scale inhibitors to ensure it had low adsorption and was able to propagate deep into the formation before being adsorbed from the supersaturated brine.\u0000 Coreflood studies using reservoir core were carried out to assess the scale risk of the LSSW/PW/SW brine, propagation and release characteristic of the short-listed scale inhibitors. The recommendation that followed the laboratory studies was to apply a batch treatment of concentrated scale inhibitor to each injector well to provide a high concentration pad of scale inhibitor that would be transported into the reservoir when the scaling LSSW/PW/SW fluid was injected. Protection was provided by continuous application of the same chemical at minimum inhibitor concentration to prevent scale formation within the topside and the desorption of the batched inhibitor within the near wellbore would prevent scale formation within this critical region. Thirteen injection wells were treated with a pad of 10% vinyl sulphonate co polymer scale inhibitor to a radial distance of 3 ft. prior to the start of LSSW/PW/SW injection. Highly scaling brine has been injected now for 16 months into the thirteen wells at an average rate of 25,000 BWPD per well with no decline in injector performance observed.\u0000 The lessons learned from this study are that changes in scaling potential within a PWRI system can be controlled by carrying out an assessment of location of scale formation and adoption of more typical production well scale squeezes treatment technology to protect the critical near wellbore region around PWRI injection wells.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84099956","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}
Lei Cheng, C. Durnell, S. Linares-Samaniego, I. Littlehales, J. Fidoe, E. Casado-Rivera
Accurate and precise analysis of scale inhibitor residuals is important to managing oilfield squeeze treatments. Phosphonate scale inhibitors are effective for the prevention and control of scale problems in oilfields. The traditional analytical technique for monitoring phosphonate scale inhibitor residuals is inductively coupled plasma optical emission spectroscopy (ICP-EOS). ICP-OES is simple and has been used for monitoring squeeze treatments for decades. However, it can only measure the total phosphorus in the system and is unable to differentiate the different forms of phosphonates in commingled samples. This paper presents a novel technique using ion chromatography and mass spectrometry (IC-MS and IC-MS/MS) for monitoring and quantifying different phosphonate scale inhibitors with high sensitivity and specificity. Ion chromatography efficiently separates phosphonate ions from other salt ions, and mass spectrometry speciates and quantitates molecular ions or fragment ions of each phosphonate. Previous work in our group (Zhang, et.al., 2014) had shown that IC-MS could be used to differentiate two phosphonates in a squeeze treatment using the characteristic molecular ions of each phosphonate. As the complexity of the squeeze treatment increases with the addition of other phosophates to the local oilfield, the development of an advanced IC-MS/MS method has been required to differentiate up to four phosphonates in a single commingled sample. This innovative technique has a detection limit of <1 ppm for each phosphonate in the mixture. The technique has been validated using both synthetic brine and field brine. Solid phase extraction cleanup work has also been performed to improve the capability of the technique in high-salinity brines. This novel analytical method will provide a powerful tool in squeeze scale management for subsea and deepwater oilfields.
{"title":"Development and Improvement of a Novel IC-MS Technique for Phosphonate Scale Inhibitors","authors":"Lei Cheng, C. Durnell, S. Linares-Samaniego, I. Littlehales, J. Fidoe, E. Casado-Rivera","doi":"10.2118/190719-MS","DOIUrl":"https://doi.org/10.2118/190719-MS","url":null,"abstract":"\u0000 Accurate and precise analysis of scale inhibitor residuals is important to managing oilfield squeeze treatments. Phosphonate scale inhibitors are effective for the prevention and control of scale problems in oilfields. The traditional analytical technique for monitoring phosphonate scale inhibitor residuals is inductively coupled plasma optical emission spectroscopy (ICP-EOS). ICP-OES is simple and has been used for monitoring squeeze treatments for decades. However, it can only measure the total phosphorus in the system and is unable to differentiate the different forms of phosphonates in commingled samples.\u0000 This paper presents a novel technique using ion chromatography and mass spectrometry (IC-MS and IC-MS/MS) for monitoring and quantifying different phosphonate scale inhibitors with high sensitivity and specificity. Ion chromatography efficiently separates phosphonate ions from other salt ions, and mass spectrometry speciates and quantitates molecular ions or fragment ions of each phosphonate. Previous work in our group (Zhang, et.al., 2014) had shown that IC-MS could be used to differentiate two phosphonates in a squeeze treatment using the characteristic molecular ions of each phosphonate. As the complexity of the squeeze treatment increases with the addition of other phosophates to the local oilfield, the development of an advanced IC-MS/MS method has been required to differentiate up to four phosphonates in a single commingled sample. This innovative technique has a detection limit of <1 ppm for each phosphonate in the mixture. The technique has been validated using both synthetic brine and field brine. Solid phase extraction cleanup work has also been performed to improve the capability of the technique in high-salinity brines. This novel analytical method will provide a powerful tool in squeeze scale management for subsea and deepwater oilfields.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88794500","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}
Da Zhu, L. Gong, Xiaoyong Qiu, Wenjihao Hu, Jun Huang, Ling Zhang, Vahidoddin Fattahpour, Mahdi Mahmoudi, Jingli Luo, Hongbo Zeng
The scaling has been found to be a major problem in thermal production, such as in the Steam-Assisted Gravity Drainage (SAGD) operation. In addition to providing a favorite environment for corrosion, scaling could result in extreme plugging in sand control devices. Therefore, any coatings for the equipment and completion in thermal production should provide significant anti-scaling surface properties. This paper presents a detailed study, including field and laboratory testing, on application of the Electroless Nickel Coating (EN-coating) in thermal production environment. Initially, EN-coated and uncoated carbon steel samples were tested in laboratory to assess the scale, hardness and adhesion of inorganic and organic materials. Successful laboratory testing lead to a field testing plan, which involves deploying the EN-coated and uncoated samples into a horizontal well for thermal production. The specimens were recovered after certain time and a comprehensive X-ray Photoelectron Spectroscopy (XPS) and Energy-Dispersive Spectroscopy (EDS) were performed to assess accumulation of fouling substances on EN-coated and uncoated carbon steel. This study suggests the application of the EN-coating technology to solve the problems caused by scale, and adhesion of organic and inorganic material in thermal production. The comprehensive laboratory testing and field data from the SAGD wells shows that EN-coating significantly improves the well integrity in the harsh thermal production environment.
{"title":"Application of Electroless Nickel Coating as a Scaling Resistant Alloy in Thermal Production","authors":"Da Zhu, L. Gong, Xiaoyong Qiu, Wenjihao Hu, Jun Huang, Ling Zhang, Vahidoddin Fattahpour, Mahdi Mahmoudi, Jingli Luo, Hongbo Zeng","doi":"10.2118/190749-MS","DOIUrl":"https://doi.org/10.2118/190749-MS","url":null,"abstract":"\u0000 The scaling has been found to be a major problem in thermal production, such as in the Steam-Assisted Gravity Drainage (SAGD) operation. In addition to providing a favorite environment for corrosion, scaling could result in extreme plugging in sand control devices. Therefore, any coatings for the equipment and completion in thermal production should provide significant anti-scaling surface properties.\u0000 This paper presents a detailed study, including field and laboratory testing, on application of the Electroless Nickel Coating (EN-coating) in thermal production environment. Initially, EN-coated and uncoated carbon steel samples were tested in laboratory to assess the scale, hardness and adhesion of inorganic and organic materials.\u0000 Successful laboratory testing lead to a field testing plan, which involves deploying the EN-coated and uncoated samples into a horizontal well for thermal production. The specimens were recovered after certain time and a comprehensive X-ray Photoelectron Spectroscopy (XPS) and Energy-Dispersive Spectroscopy (EDS) were performed to assess accumulation of fouling substances on EN-coated and uncoated carbon steel.\u0000 This study suggests the application of the EN-coating technology to solve the problems caused by scale, and adhesion of organic and inorganic material in thermal production. The comprehensive laboratory testing and field data from the SAGD wells shows that EN-coating significantly improves the well integrity in the harsh thermal production environment.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73063592","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper describes a number of different evaporative processes which can cause flow assurance issues within oilfield production systems including chemical application via gas lift systems, halite deposition and gunking in injection lines. Similarities and differences are described and laboratory test methods are presented for each case. While the challenges all involve evaporative processes, each system is different and requires suitable approaches to evaluate and mitigate the risks. These attempt to mimic the field system in the laboratory and allow observation under controlled conditions. Laboratory test methods vary from basic static bottle tests, through glass capillaries in autoclaves to dynamic tests using brine and a partially saturated gas phase, or neat chemical and dry gas lift media. In particular, the challenges when applying a chemical via a gas lift system will be described including field case studies. Static tests with unlimited volume to evaporate produce a worst case for any evaporative process. However, it is frequently too severe to produce any useful results. Instead a test regime should be designed to mimic the field conditions. For example, evaporation within a pressure vessel can mimic the self-limiting process within a downhole injection line. Application of a chemical via a gas lift system requires a dynamic test where hot pressurised dry gas and neat chemical are co-injected with continual monitoring of gunking as indicated by flow path restrictions. Halites require a similar dynamic test method but with extensive modelling of the in situ saturation ratio to fully understand the system. This paper will present case studies, summarise our understanding of the different evaporative processes, and give best practice guidelines for laboratory evaluation of the risks and mitigation strategies.
{"title":"Evaluating Evaporative Processes - Gas Lift Chemical Applications, Halites and Gunking","authors":"N. Goodwin, G. Graham","doi":"10.2118/190712-MS","DOIUrl":"https://doi.org/10.2118/190712-MS","url":null,"abstract":"\u0000 This paper describes a number of different evaporative processes which can cause flow assurance issues within oilfield production systems including chemical application via gas lift systems, halite deposition and gunking in injection lines. Similarities and differences are described and laboratory test methods are presented for each case.\u0000 While the challenges all involve evaporative processes, each system is different and requires suitable approaches to evaluate and mitigate the risks. These attempt to mimic the field system in the laboratory and allow observation under controlled conditions. Laboratory test methods vary from basic static bottle tests, through glass capillaries in autoclaves to dynamic tests using brine and a partially saturated gas phase, or neat chemical and dry gas lift media. In particular, the challenges when applying a chemical via a gas lift system will be described including field case studies.\u0000 Static tests with unlimited volume to evaporate produce a worst case for any evaporative process. However, it is frequently too severe to produce any useful results. Instead a test regime should be designed to mimic the field conditions. For example, evaporation within a pressure vessel can mimic the self-limiting process within a downhole injection line. Application of a chemical via a gas lift system requires a dynamic test where hot pressurised dry gas and neat chemical are co-injected with continual monitoring of gunking as indicated by flow path restrictions. Halites require a similar dynamic test method but with extensive modelling of the in situ saturation ratio to fully understand the system.\u0000 This paper will present case studies, summarise our understanding of the different evaporative processes, and give best practice guidelines for laboratory evaluation of the risks and mitigation strategies.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89905260","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. Lu, G. Ruan, K. Harouaka, Dushanee Sriyarathne, Wei Li, Guannan Deng, Yue Zhao, Xing-lei Wang, A. Kan, M. Tomson
Deposition of inorganic scale has always been a common problem in oilfield pipes, especially in raising safety risk and producing cost. However, the fundamentals of deposition mechanism and the effect of various surface, temperature, flow rate and inhibitors on deposition rate has not been systematically studied. The objective of this research is to reveal the process of barium sulfate deposition on stainless steel surfaces. In this work a novel continuous flow apparatus has been set up to enable further investigation of deposition rate, crystal size and morphology and the effect of scale inhibitor. In this apparatus supersaturate barium sulfate solution is mixed and passed through a 3 feet stainless steel tubing with ID = 0.04 inch or 0.21 inch at 70 to 120 degree C. The barium concentration is measured at the effluent to quantify the concentration drop. After 1 to 200 hours the tubing is cut into pieces to measure the barite deposition amount and observe the barite crystal morphology using SEM. Under the experimental conditions, the deposition rate along the stainless steel tubing can be modelled by second order crystal growth kinetics, the SEM micrograph also shows that most of deposited barite is micrometer sized crystals. The highest deposition rate happens at the beginning of the tubing even before the expected induction time of bariums sulfate. The results indicated that the deposition happens even before the mixed solution is expected to form particles, which suggest that the heterogeneous nucleation might be the dominate mechanism in the initial stage, then crystal growth takes place and governs the deposition. The mechanism of scale attachment to tubing surface has never been well-understood. The apparatus in this work provides a reliable and reproducible method to investigate barium sulfate deposition. The findings in this research will enhance our knowledge of mineral scale deposition process, and aid the use of inhibitors in mineral scale control.
{"title":"A Novel View of Barium Sulfate Deposition in Stainless Steel Tubing","authors":"A. Lu, G. Ruan, K. Harouaka, Dushanee Sriyarathne, Wei Li, Guannan Deng, Yue Zhao, Xing-lei Wang, A. Kan, M. Tomson","doi":"10.2118/190696-MS","DOIUrl":"https://doi.org/10.2118/190696-MS","url":null,"abstract":"\u0000 Deposition of inorganic scale has always been a common problem in oilfield pipes, especially in raising safety risk and producing cost. However, the fundamentals of deposition mechanism and the effect of various surface, temperature, flow rate and inhibitors on deposition rate has not been systematically studied. The objective of this research is to reveal the process of barium sulfate deposition on stainless steel surfaces.\u0000 In this work a novel continuous flow apparatus has been set up to enable further investigation of deposition rate, crystal size and morphology and the effect of scale inhibitor. In this apparatus supersaturate barium sulfate solution is mixed and passed through a 3 feet stainless steel tubing with ID = 0.04 inch or 0.21 inch at 70 to 120 degree C. The barium concentration is measured at the effluent to quantify the concentration drop. After 1 to 200 hours the tubing is cut into pieces to measure the barite deposition amount and observe the barite crystal morphology using SEM.\u0000 Under the experimental conditions, the deposition rate along the stainless steel tubing can be modelled by second order crystal growth kinetics, the SEM micrograph also shows that most of deposited barite is micrometer sized crystals. The highest deposition rate happens at the beginning of the tubing even before the expected induction time of bariums sulfate. The results indicated that the deposition happens even before the mixed solution is expected to form particles, which suggest that the heterogeneous nucleation might be the dominate mechanism in the initial stage, then crystal growth takes place and governs the deposition.\u0000 The mechanism of scale attachment to tubing surface has never been well-understood. The apparatus in this work provides a reliable and reproducible method to investigate barium sulfate deposition. The findings in this research will enhance our knowledge of mineral scale deposition process, and aid the use of inhibitors in mineral scale control.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"154 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77508181","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 inhibitor squeeze treatments are used to prevent scale deposition in production wells. A treatment consists of injecting a scale inhibitor slug at a concentration between 5 and 15%, referred to as the main treatment, followed by an overflush, which will push the chemical slug deeper into the reservoir. During injection, the stages might undergo some degree of mixing in the tubing. This paper addresses the impact such mixing would have on the squeeze lifetime. A consequence of mixing between main treatment and overflush stages in the well tubing would be that although the same overall mass of scale inhibitor was injected, it would be distributed over a larger volume of water and therefore be exposed to the rock formation at a lower concentration than planned in the design. The degree of mixing in the tubing depends on a number of factors, such as tubing length and diameter, and the pumping rate. The phenomenon is described by the longitudinal dispersion coefficient, which may be calculated. The resulting calculation may be defined as the spreading of a solute along the longitudinal axis, which leads to the spread of an initial high concentration slug with a low spatial variance to a final stage of low concentration with high spatial variance. The main objective of the paper is to study the effect of the degree of mixing of the main and overflush stages on the squeeze treatment lifetime. The net effect of full mixing would be that instead of there being two different stages at very different scale inhibitor concentration, a single stage at a lower concentration might be exposed to the rock formation. Two mixing profiles were considered, a short and long tubing; where the total injected volume is greater than and less than the total tubing volume, respectively. A number of levels of mixing were considered and compared to the base case, where no mixing was allowed. The results showed that squeeze lifetime is not significantly reduced if mixing occurs in a short tubing interval, whereas it can be reduced by up to 20% in a longer tubing interval.
{"title":"Effect of Squeeze Treatment Stages Mixing During Injection on Lifetime","authors":"O. Vazquez, E. Mackay, Manuel Raga, G. Ross","doi":"10.2118/190751-MS","DOIUrl":"https://doi.org/10.2118/190751-MS","url":null,"abstract":"\u0000 Scale inhibitor squeeze treatments are used to prevent scale deposition in production wells. A treatment consists of injecting a scale inhibitor slug at a concentration between 5 and 15%, referred to as the main treatment, followed by an overflush, which will push the chemical slug deeper into the reservoir. During injection, the stages might undergo some degree of mixing in the tubing. This paper addresses the impact such mixing would have on the squeeze lifetime. A consequence of mixing between main treatment and overflush stages in the well tubing would be that although the same overall mass of scale inhibitor was injected, it would be distributed over a larger volume of water and therefore be exposed to the rock formation at a lower concentration than planned in the design. The degree of mixing in the tubing depends on a number of factors, such as tubing length and diameter, and the pumping rate. The phenomenon is described by the longitudinal dispersion coefficient, which may be calculated.\u0000 The resulting calculation may be defined as the spreading of a solute along the longitudinal axis, which leads to the spread of an initial high concentration slug with a low spatial variance to a final stage of low concentration with high spatial variance. The main objective of the paper is to study the effect of the degree of mixing of the main and overflush stages on the squeeze treatment lifetime. The net effect of full mixing would be that instead of there being two different stages at very different scale inhibitor concentration, a single stage at a lower concentration might be exposed to the rock formation. Two mixing profiles were considered, a short and long tubing; where the total injected volume is greater than and less than the total tubing volume, respectively. A number of levels of mixing were considered and compared to the base case, where no mixing was allowed. The results showed that squeeze lifetime is not significantly reduced if mixing occurs in a short tubing interval, whereas it can be reduced by up to 20% in a longer tubing interval.","PeriodicalId":10969,"journal":{"name":"Day 2 Thu, June 21, 2018","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-06-20","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75846686","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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