Zongming Xiu, P. Dufils, Jia Zhou, A. Cadix, Kevan Hatchman, Tom Decoster, P. Ferlin
As waxy crude oil comes to the surface, it will cool down and causing the waxy fraction to gel. The gelled crude chokes the well, leading to restricted or blocked production and costly downtime for operators. One of the most common chemical solutions to address the wax deposit challenge is the addition of wax inhibitors or pour point depressants (PPDs) to the production stream. However, most of the PPD's used in the field are organic solvent-based polymers, which require large quantities of hazardous organic solvents such as xylene and toluene. To propose an improved solution, a water-based amphiphilic PPD polymer dispersion system, synthesized using controlled radical polymerization technology has recently been developed. This specifically designed block copolymer is synthesized with a hydrophilic polymeric head group and a hydrophobic tail. The macromolecular design was specifically optimized to control particle size to create unique and stable amphiphilic PPD dispersion. The viscosity of the PPD, at high activity of about 40%, is between 200 and 250 cps at room temperature with a milky color, and it remains stable to 200°C under 500psi. Also, the PPD dispersion itself has a pour point of −30°C, and it can be easily formulated to be pumpable under −40°C. For performance evaluation, the water-based PPD dispersion was tested using a standard cold-finger apparatus and a pour point tester on crude oils from various global regions. The results showed that this PPD dispersion not only significantly reduced crude oil wax deposition by nearly 70%, but it also reduced the pour point of the crude by typically 18°C. Overall, the current research performed on macromolecular architecture design shows that this block polymer technology allows polymer adjustment to meet application needs for various crude types, and to tackle this important flow assurance challenges.
{"title":"Amphiphilic Wax Inhibitor for Tackling Crude Oil Wax Deposit Challenges","authors":"Zongming Xiu, P. Dufils, Jia Zhou, A. Cadix, Kevan Hatchman, Tom Decoster, P. Ferlin","doi":"10.2118/193593-MS","DOIUrl":"https://doi.org/10.2118/193593-MS","url":null,"abstract":"\u0000 As waxy crude oil comes to the surface, it will cool down and causing the waxy fraction to gel. The gelled crude chokes the well, leading to restricted or blocked production and costly downtime for operators. One of the most common chemical solutions to address the wax deposit challenge is the addition of wax inhibitors or pour point depressants (PPDs) to the production stream. However, most of the PPD's used in the field are organic solvent-based polymers, which require large quantities of hazardous organic solvents such as xylene and toluene. To propose an improved solution, a water-based amphiphilic PPD polymer dispersion system, synthesized using controlled radical polymerization technology has recently been developed. This specifically designed block copolymer is synthesized with a hydrophilic polymeric head group and a hydrophobic tail. The macromolecular design was specifically optimized to control particle size to create unique and stable amphiphilic PPD dispersion. The viscosity of the PPD, at high activity of about 40%, is between 200 and 250 cps at room temperature with a milky color, and it remains stable to 200°C under 500psi. Also, the PPD dispersion itself has a pour point of −30°C, and it can be easily formulated to be pumpable under −40°C. For performance evaluation, the water-based PPD dispersion was tested using a standard cold-finger apparatus and a pour point tester on crude oils from various global regions. The results showed that this PPD dispersion not only significantly reduced crude oil wax deposition by nearly 70%, but it also reduced the pour point of the crude by typically 18°C. Overall, the current research performed on macromolecular architecture design shows that this block polymer technology allows polymer adjustment to meet application needs for various crude types, and to tackle this important flow assurance challenges.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"97 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85760060","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}
Andrew Rafferty, Christine Stewart-Liddon, C. Simpson, P. Hammonds, G. Graham, P. Maskell
It is known that some H2S scavengers have the potential to cause fouling either from reaction products or by the influence of their chemistry on brine scaling potential. A series of methods for assessing the performance of the H2S scavengers and the likely hood of the generation of unwanted reaction by products is described along with the utility of each test methodology under different production conditions The performance of triazine- and aldehyde-based H2S scavengers are compared in a suite of laboratory tests, including liquid phase tests examining residual sulphides in solution and by measuring H2S in the gas phase using an in situ H2S detector. The tests are capable of differentiating between the performances of different H2S scavengers over a range of different test conditions and are applicable to those of the production process where scavengers are used. The work also shows that the absolute performance and relative performance or ranking of different scavengers is affected by the test methodology adopted and the work therefore illustrates the importance of selecting an appropriate test methodology for the intended field application. The efficiency of the scavengers was determined both under bulk liquid phase conditions and also by the contact time required to reduce the initial gas phase H2S concentration to the desired level and by calculating the scavenging capacity. This work presents both apparatus and methods which can be used for the evaluation and comparison of H2S scavengers. It describes primarily experimental design aspects and challenges associated with differentiating between free (unscavenged) H2S and reacted (i.e. scavenged / trapped) H2S in bulk liquid phase tests often utilised for preliminary screening of scavengers and recommends a procedure to allow such tests to be conducted routinely. Works then compare results with more conventional gas stream monitoring approaches. This work presented and the approaches described will then assist in the screening and product selection process and provides information on the conditions under which un-desirable solid by-products may be generated.
{"title":"Methodology to Evaluate the Performance and Stability of Hydrogen Sulphide Scavengers","authors":"Andrew Rafferty, Christine Stewart-Liddon, C. Simpson, P. Hammonds, G. Graham, P. Maskell","doi":"10.2118/193571-MS","DOIUrl":"https://doi.org/10.2118/193571-MS","url":null,"abstract":"\u0000 It is known that some H2S scavengers have the potential to cause fouling either from reaction products or by the influence of their chemistry on brine scaling potential. A series of methods for assessing the performance of the H2S scavengers and the likely hood of the generation of unwanted reaction by products is described along with the utility of each test methodology under different production conditions\u0000 The performance of triazine- and aldehyde-based H2S scavengers are compared in a suite of laboratory tests, including liquid phase tests examining residual sulphides in solution and by measuring H2S in the gas phase using an in situ H2S detector. The tests are capable of differentiating between the performances of different H2S scavengers over a range of different test conditions and are applicable to those of the production process where scavengers are used. The work also shows that the absolute performance and relative performance or ranking of different scavengers is affected by the test methodology adopted and the work therefore illustrates the importance of selecting an appropriate test methodology for the intended field application. The efficiency of the scavengers was determined both under bulk liquid phase conditions and also by the contact time required to reduce the initial gas phase H2S concentration to the desired level and by calculating the scavenging capacity.\u0000 This work presents both apparatus and methods which can be used for the evaluation and comparison of H2S scavengers. It describes primarily experimental design aspects and challenges associated with differentiating between free (unscavenged) H2S and reacted (i.e. scavenged / trapped) H2S in bulk liquid phase tests often utilised for preliminary screening of scavengers and recommends a procedure to allow such tests to be conducted routinely. Works then compare results with more conventional gas stream monitoring approaches. This work presented and the approaches described will then assist in the screening and product selection process and provides information on the conditions under which un-desirable solid by-products may be generated.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80967380","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}
F. C. D. Rezende, R. B. Rabelo, Lílian Kinouti, C. Ewbank, O. Poltronieri
In this study, a novel surfactant for flowback aid application was developed based on an optimization of well-known non-ionic surfactants. The objective was to meet intrinsic surfactant properties, such as high cloud point (CP), low surface tension (ST), adequate contact angle (CA) and low critical micelle concentration (CMC). In addition to the essential physical-chemical properties, improvement in fluid recovery and emulsion compatibility were also targeted. The surfactants were optimized by tailoring the hydrophilic head through controlled introduction of ethylene oxide and propylene oxide into different hydrophobic chains. Surface tension measurements were made with a Dataphysics Instruments model OCA-15. Contact angles were measured using the sessile-drop method. The CMC concentration and cloud point were also conducted for physical chemical characterization. For the fluid recovery evaluation, flowback solutions were poured through 150g of 60/150 mesh- dry porous media contained in a 7 cm-inner-diameter, 9.5- cm-long column. Emulsion compatibility tests were also carried out using different proportions of crude oil and brine. This paper evaluates various flowback additives in hydraulic fracturing applications between linear and branched alkoxylated surfactants. High cloud point enables a wide range of temperature applications and an increase in EO content showed an increase in cloud point values, contrary to PO effect. Nevertheless, CMC measurements showed that for an optimum scenario, EO addition should not be high, because undesired increases in CMC values may occur, which will affect the final surfactant dosage needed. All flowback aids demonstrated low surface tension as expected (approximately below 32 mN/m), but each being different in terms of surface wettability (contact angle), which could not be correlated with surfactant structure. Fluid recovery and kinetics of emulsion breakage increased significantly with different alkoxylation adjustments. For the new flowback aid developed, the fluid recovery was improved when compared against standard surfactants. Additionally, significant improvement was also found during emulsion breakage evaluation in terms of superior kinetics, final breakage, and water quality. This work provided a better understanding of how EO/PO affects intrinsic surfactant properties and enabled to find a surfactant that offers several benefits in terms of fluid recovery and non-emulsification of crude oil and water.
{"title":"Tailoring Alkoxylation of Flowback Aid Surfactants for Maximum Efficiency","authors":"F. C. D. Rezende, R. B. Rabelo, Lílian Kinouti, C. Ewbank, O. Poltronieri","doi":"10.2118/193623-MS","DOIUrl":"https://doi.org/10.2118/193623-MS","url":null,"abstract":"\u0000 In this study, a novel surfactant for flowback aid application was developed based on an optimization of well-known non-ionic surfactants. The objective was to meet intrinsic surfactant properties, such as high cloud point (CP), low surface tension (ST), adequate contact angle (CA) and low critical micelle concentration (CMC). In addition to the essential physical-chemical properties, improvement in fluid recovery and emulsion compatibility were also targeted. The surfactants were optimized by tailoring the hydrophilic head through controlled introduction of ethylene oxide and propylene oxide into different hydrophobic chains.\u0000 Surface tension measurements were made with a Dataphysics Instruments model OCA-15. Contact angles were measured using the sessile-drop method. The CMC concentration and cloud point were also conducted for physical chemical characterization. For the fluid recovery evaluation, flowback solutions were poured through 150g of 60/150 mesh- dry porous media contained in a 7 cm-inner-diameter, 9.5- cm-long column. Emulsion compatibility tests were also carried out using different proportions of crude oil and brine.\u0000 This paper evaluates various flowback additives in hydraulic fracturing applications between linear and branched alkoxylated surfactants. High cloud point enables a wide range of temperature applications and an increase in EO content showed an increase in cloud point values, contrary to PO effect. Nevertheless, CMC measurements showed that for an optimum scenario, EO addition should not be high, because undesired increases in CMC values may occur, which will affect the final surfactant dosage needed. All flowback aids demonstrated low surface tension as expected (approximately below 32 mN/m), but each being different in terms of surface wettability (contact angle), which could not be correlated with surfactant structure. Fluid recovery and kinetics of emulsion breakage increased significantly with different alkoxylation adjustments. For the new flowback aid developed, the fluid recovery was improved when compared against standard surfactants. Additionally, significant improvement was also found during emulsion breakage evaluation in terms of superior kinetics, final breakage, and water quality. This work provided a better understanding of how EO/PO affects intrinsic surfactant properties and enabled to find a surfactant that offers several benefits in terms of fluid recovery and non-emulsification of crude oil and water.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87120435","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}
Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance. In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and pH are the secondary cause affecting scale formation in the reservoir. During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.
{"title":"Simulation Study of Scale Management During Hydraulic Fracturing in Unconventional Reservoirs","authors":"Ali Abouie, A. Sanaei, K. Sepehrnoori","doi":"10.2118/193570-MS","DOIUrl":"https://doi.org/10.2118/193570-MS","url":null,"abstract":"\u0000 Geochemical scale formation and deposition in reservoir is a common problem in upstream oil and gas industry, which results in equipment corrosion, wellbore plugging, and production decline. In unconventional reservoirs, the negative effect of scale formation becomes more pronounced as it can severely damage the conductivity of hydraulic fractures. Hence, it is necessary to predict the effect of scale deposition on fracture conductivity and production performance.\u0000 In this work, an integrated reactive-transport simulator is utilized to model geochemical reactions along with transport equations in conventional and unconventional reservoirs considering the damage to the fracture and formation matrix. Hence, a compositional reservoir simulator (UTCOMP), which is integrated with IPhreeqc, is utilized to predict geochemical scale formation in formation matrix and hydraulic fractures. IPhreeqc offers extensive capabilities for modeling geochemical reactions including local thermodynamic equilibrium and kinetics. Based on the amount of scale formation, porosity, permeability, and fracture aperture are modified to determine the production loss. The results suggested that interaction of the formation water/brine and injection water/hydraulic fracturing fluid is the primary cause for scale formation. The physicochemical properties such as pressure, temperature, and pH are the secondary cause affecting scale formation in the reservoir.\u0000 During hydraulic fracturing, precipitation of barite and dissolution of calcite are identified to be the main reactions, which occur as a result of interaction between the formation brine, formation mineral composition, and injection water/hydraulic fracturing fluid. Calcite dissolution can increase the matrix porosity and permeability while barite precipitation has an opposite effect. Therefore, the overall effect and final results depend on several parameters such as HFF composition, HFF injection rate, and formation mineral/brine. Based on the fracturing fluid composition and its invasion depth in this study, the effect of barite precipitation was dominant with negative impact on cumulative gas production. The outcome of this study is a comprehensive tool for prediction of scale deposition in the reservoir which can help operators to select optimum fracturing fluid and operating conditions.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"6 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88349681","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}
M. M. A. Kalbani, M. Jordan, E. Mackay, K. Sorbie, L. Nghiem
Barium Sulphate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing water flooding. Chemical Enhanced Oil Recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulphate co-production behaviour, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer (P), surfactant (S) and surfactant-polymer (SP) flooding cEOR processes. Reservoir simulation has been used in this study, employing homogenous and heterogeneous 2D areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of surfactant and polymer (e.g. oil-water interfacial tension, IFT, polymer viscosity and surfactant and polymer adsorption). Assessment is made of the minimum inhibitor concentration (MIC) required to control scale that is predicted to occur due to changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor during squeeze treatments in the production wells is modelled. The high viscosity and more stable polymer slug reduces the mixing between the injected and the formation brines, reducing BaSO4 scale precipitation in the formation and delaying the potential scale risk in the producer wellbore compared to normal water flooding. Polymer adsorption causes retardation of the polymer front compared to the sulphate front, accelerating the scale risk in the wellbore. Polymer with low salinity make-up brine and low sulphate concentration not only improves polymer viscosity and enhances recovery, it also delays and reduces the scale risk in the formation and the producer. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the water flooding case, depending on the IFT, ME phase type, the injected salinity and sulphate concentration. In SP flooding, low salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the changing brine composition due to ion reactions affected the required MIC values over time. The impact of the MIC and salinity changes on inhibitor retention and release then influences the treatment volumes required to control scale over field life. The study shows that barium and sulphate co-production and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities), on the oil-water IFT and on the le
{"title":"Barium Sulphate Scaling and Control during Polymer, Surfactant and Surfactant-Polymer Flooding","authors":"M. M. A. Kalbani, M. Jordan, E. Mackay, K. Sorbie, L. Nghiem","doi":"10.2118/193575-MS","DOIUrl":"https://doi.org/10.2118/193575-MS","url":null,"abstract":"\u0000 Barium Sulphate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing water flooding. Chemical Enhanced Oil Recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulphate co-production behaviour, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer (P), surfactant (S) and surfactant-polymer (SP) flooding cEOR processes.\u0000 Reservoir simulation has been used in this study, employing homogenous and heterogeneous 2D areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of surfactant and polymer (e.g. oil-water interfacial tension, IFT, polymer viscosity and surfactant and polymer adsorption). Assessment is made of the minimum inhibitor concentration (MIC) required to control scale that is predicted to occur due to changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor during squeeze treatments in the production wells is modelled.\u0000 The high viscosity and more stable polymer slug reduces the mixing between the injected and the formation brines, reducing BaSO4 scale precipitation in the formation and delaying the potential scale risk in the producer wellbore compared to normal water flooding. Polymer adsorption causes retardation of the polymer front compared to the sulphate front, accelerating the scale risk in the wellbore. Polymer with low salinity make-up brine and low sulphate concentration not only improves polymer viscosity and enhances recovery, it also delays and reduces the scale risk in the formation and the producer. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the water flooding case, depending on the IFT, ME phase type, the injected salinity and sulphate concentration. In SP flooding, low salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the changing brine composition due to ion reactions affected the required MIC values over time. The impact of the MIC and salinity changes on inhibitor retention and release then influences the treatment volumes required to control scale over field life.\u0000 The study shows that barium and sulphate co-production and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities), on the oil-water IFT and on the le","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83417336","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}
Jian Lu, Dale Toups, B. Lamoureux, Stephen M. Williams, Joshua Williams
Water, oil and solid field sample characterizations are essential to scale management, corrosion and flow assurance surveillance. From sample collection to getting lab test results take weeks to even months for off-shore locations, while operation changes can happen in hours or days. During the sample transportation process, water and solid samples are often oxidized with iron species dropped out of solution or changed to oxide. For fast operational feedback and "freshest" sample measurement, on-site composition analyses are highly desirable. Typical lab analyzers, such as ICP (inductively coupled plasma) and IC (Ion Chromatography), are highly specialized and requires regular chemical supplies and maintenance. So many lab analyzers are not suitable for on-site use. This paper reports the development of test methods using a benchtop X-Ray Fluorescence (XRF) analyzer for oil field samples and field application at Gulf of Mexico offshore locations. The Benchtop XRF analyzer is very user-friendly, requires minimal sample preparation, and leaves little room for human error. Once set up, the analyzer provides fast on-site feedback at low cost, and can work with all non-gas samples. With calibrated methods, this analyzer can provide quantitative measurement for elements in water or oil. For other sample types, such as solid, slurry, mix and metals, this analyzer can be used to do qualitative measurements for trending and component identification. This on-site surveillance tool has proven to be able to provide fast and accurate data on key elements for scale, corrosion and flow assurance management at a low cost. Examples of operation decisions based on this analyzer results will be presented. This tool has demonstrated the ability to provide timely data for preventing plugging/fouling, checking chemical effectiveness, improved integrity surveillance and well flowback surveillance. Use of this tool during maintenance/turnaround helps to build up a better picture on areas with various deposits.
{"title":"On-Site Fluids and Solids Characterization with Benchtop XRF Analyzer","authors":"Jian Lu, Dale Toups, B. Lamoureux, Stephen M. Williams, Joshua Williams","doi":"10.2118/193545-MS","DOIUrl":"https://doi.org/10.2118/193545-MS","url":null,"abstract":"Water, oil and solid field sample characterizations are essential to scale management, corrosion and flow assurance surveillance. From sample collection to getting lab test results take weeks to even months for off-shore locations, while operation changes can happen in hours or days. During the sample transportation process, water and solid samples are often oxidized with iron species dropped out of solution or changed to oxide. For fast operational feedback and \"freshest\" sample measurement, on-site composition analyses are highly desirable. Typical lab analyzers, such as ICP (inductively coupled plasma) and IC (Ion Chromatography), are highly specialized and requires regular chemical supplies and maintenance. So many lab analyzers are not suitable for on-site use. This paper reports the development of test methods using a benchtop X-Ray Fluorescence (XRF) analyzer for oil field samples and field application at Gulf of Mexico offshore locations. The Benchtop XRF analyzer is very user-friendly, requires minimal sample preparation, and leaves little room for human error. Once set up, the analyzer provides fast on-site feedback at low cost, and can work with all non-gas samples. With calibrated methods, this analyzer can provide quantitative measurement for elements in water or oil. For other sample types, such as solid, slurry, mix and metals, this analyzer can be used to do qualitative measurements for trending and component identification. This on-site surveillance tool has proven to be able to provide fast and accurate data on key elements for scale, corrosion and flow assurance management at a low cost. Examples of operation decisions based on this analyzer results will be presented. This tool has demonstrated the ability to provide timely data for preventing plugging/fouling, checking chemical effectiveness, improved integrity surveillance and well flowback surveillance. Use of this tool during maintenance/turnaround helps to build up a better picture on areas with various deposits.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89747933","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 considers the placement challenge in selected wells in a North Sea Field and presents the importance of understanding reservoir properties such as relative permeability, mobility and fluid in place when attempting to simulate treatments in complex wells such as these. The work presents the challenges and solutions offered to minimise the scale risk in this mature field as a result of changes in the overall drainage strategy. Many wells in the North Sea Field are complex and produce from multiple heterogeneous formations which makes them difficult to treat, and so effective placement is vital to mitigate downhole scaling. The wells highlighted in this paper were originally planned for minimal interventions. However as the field development plan matured an increased (albeit mild) sulphate scaling risk became evident in several production wells. Therefore, pre-emptive squeeze treatments were planned to mitigate downhole barium sulphate scaling. Given the heterogeneity in the formation this resulted in potential risks in the event that squeeze treatments could not be designed to give effective placement. This paper presents the placement challenge that is seen in these wells in addition to potential methods of overcoming these challenges. Effective placement does not necessarily mean placement into all producing layers, but means placement of inhibitor into layers upstream of any potential mixing point of scaling brines. Therefore, this work highlights the necessary placement required for effective inhibition and the corresponding treatment designs that may achieve this. One treatment injection strategy to assist effective placement is the use of a staged diversion treatment which is simulated using a near-wellbore placement model. This paper documents a case study of modelling placement, and the corresponding squeeze return, in a mature North Sea Field. It highlights the important influence of reservoir properties such as relative permeability effects (in addition to permeability, porosity, fluid mobility etc.) and how these are used such that chemical treatments in complex heterogeneous wells can be readily simulated without the necessity of using complex full field reservoir simulators.
{"title":"A Placement Case Study for a Well in the North Sea Field","authors":"A. Kaur, R. Stalker, G. Graham","doi":"10.2118/193584-MS","DOIUrl":"https://doi.org/10.2118/193584-MS","url":null,"abstract":"\u0000 This paper considers the placement challenge in selected wells in a North Sea Field and presents the importance of understanding reservoir properties such as relative permeability, mobility and fluid in place when attempting to simulate treatments in complex wells such as these. The work presents the challenges and solutions offered to minimise the scale risk in this mature field as a result of changes in the overall drainage strategy.\u0000 Many wells in the North Sea Field are complex and produce from multiple heterogeneous formations which makes them difficult to treat, and so effective placement is vital to mitigate downhole scaling. The wells highlighted in this paper were originally planned for minimal interventions. However as the field development plan matured an increased (albeit mild) sulphate scaling risk became evident in several production wells. Therefore, pre-emptive squeeze treatments were planned to mitigate downhole barium sulphate scaling. Given the heterogeneity in the formation this resulted in potential risks in the event that squeeze treatments could not be designed to give effective placement.\u0000 This paper presents the placement challenge that is seen in these wells in addition to potential methods of overcoming these challenges. Effective placement does not necessarily mean placement into all producing layers, but means placement of inhibitor into layers upstream of any potential mixing point of scaling brines. Therefore, this work highlights the necessary placement required for effective inhibition and the corresponding treatment designs that may achieve this. One treatment injection strategy to assist effective placement is the use of a staged diversion treatment which is simulated using a near-wellbore placement model.\u0000 This paper documents a case study of modelling placement, and the corresponding squeeze return, in a mature North Sea Field. It highlights the important influence of reservoir properties such as relative permeability effects (in addition to permeability, porosity, fluid mobility etc.) and how these are used such that chemical treatments in complex heterogeneous wells can be readily simulated without the necessity of using complex full field reservoir simulators.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82039513","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}
Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar ("AS-C") and asphaltenes from bitumen ("AS-B") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.
{"title":"The Effect of Molecular Composition on the Electro-Deposition of Asphaltene","authors":"Shunxiang Xia, K. Kostarelos","doi":"10.2118/193612-MS","DOIUrl":"https://doi.org/10.2118/193612-MS","url":null,"abstract":"\u0000 Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar (\"AS-C\") and asphaltenes from bitumen (\"AS-B\") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"89 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84510428","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}
As the oil and gas industry continues to operate in more complex and deeper water environments downhole scale control via scale squeeze treatments becomes an ever-increasing technical challenge. It is therefore essential that effective scale management strategies are adopted which incorporate suitable scale inhibitor (SI) selection, analysis and treatment design procedures to provide optimal and cost-effective squeeze treatment lifetimes to maximise oil production and reduce well intervention costs. In this paper key factors are evaluated in order to provide a guidance to selecting a suitable treatment strategy for downhole scale control in co-mingled sub-sea well and the impact of chemical retention, minimum inhibitor concentration (MIC), limit of quantifiable detection (LOQD) and well dilution factors on treatment design and strategy are discussed. The pros and cons of different treatment strategies are presented in this paper and consideration is given to following three treatment strategies: Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months;Treating individual wells with tagged versions of the same scale inhibitor chemical;Treating individual wells with different scale inhibitors. Options (ii) and (iii) offer the ability to design similar treatment lifetimes for each well but have the flexibility to monitor wells individually and re-squeeze when required. Examples are provided for treatment options (ii) and (iii) based upon a field example to illustrate the design concepts for fluorescent (F) and phosphorus (P) tagged polymers in two co-mingled wells and a theoretical example for treating three co-mingled wells with different scale inhibitors, one of which could be a phosphonate with two tagged polymers. This paper presents an overview of the key factors that influence chemical selection and treatment design for co-mingled wells in the same flow line. In addition, it will highlight important concepts to provide guidance for the design of effective treatment strategies for squeezing co-mingled wells in sub-sea and deepwater environments.
{"title":"Strategies for Squeezing Co-Mingled Wells in the Same Flow Line in Sub-Sea and Deepwater Environments - Guidelines for Scale Inhibitor Selection and Effective Treatment Strategies and Design","authors":"S. Heath, N. Gjøsund, D. Dugué","doi":"10.2118/193558-MS","DOIUrl":"https://doi.org/10.2118/193558-MS","url":null,"abstract":"\u0000 As the oil and gas industry continues to operate in more complex and deeper water environments downhole scale control via scale squeeze treatments becomes an ever-increasing technical challenge. It is therefore essential that effective scale management strategies are adopted which incorporate suitable scale inhibitor (SI) selection, analysis and treatment design procedures to provide optimal and cost-effective squeeze treatment lifetimes to maximise oil production and reduce well intervention costs.\u0000 In this paper key factors are evaluated in order to provide a guidance to selecting a suitable treatment strategy for downhole scale control in co-mingled sub-sea well and the impact of chemical retention, minimum inhibitor concentration (MIC), limit of quantifiable detection (LOQD) and well dilution factors on treatment design and strategy are discussed. The pros and cons of different treatment strategies are presented in this paper and consideration is given to following three treatment strategies: Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months;Treating individual wells with tagged versions of the same scale inhibitor chemical;Treating individual wells with different scale inhibitors.\u0000 Options (ii) and (iii) offer the ability to design similar treatment lifetimes for each well but have the flexibility to monitor wells individually and re-squeeze when required.\u0000 Examples are provided for treatment options (ii) and (iii) based upon a field example to illustrate the design concepts for fluorescent (F) and phosphorus (P) tagged polymers in two co-mingled wells and a theoretical example for treating three co-mingled wells with different scale inhibitors, one of which could be a phosphonate with two tagged polymers.\u0000 This paper presents an overview of the key factors that influence chemical selection and treatment design for co-mingled wells in the same flow line. In addition, it will highlight important concepts to provide guidance for the design of effective treatment strategies for squeezing co-mingled wells in sub-sea and deepwater environments.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84040934","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 scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application. In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test. To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches. This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits
{"title":"Dissolution Study of Field Deposits for Oilfield Scale Mitigation and Remediation","authors":"Chao Yan, Wei Wang, Wei Wei","doi":"10.2118/193611-MS","DOIUrl":"https://doi.org/10.2118/193611-MS","url":null,"abstract":"\u0000 Formation of scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application.\u0000 In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test.\u0000 To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches.\u0000 This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88155363","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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