Khatere Sokhanvarian, C. Stanciu, Jorge Fernandez, A. Ibrahim, H. Nasr-El-Din
Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants. This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively. Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid. This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.
{"title":"Novel Non-Aromatic Non-Ionic Surfactants to Target Deep Carbonate Stimulation","authors":"Khatere Sokhanvarian, C. Stanciu, Jorge Fernandez, A. Ibrahim, H. Nasr-El-Din","doi":"10.2118/193596-MS","DOIUrl":"https://doi.org/10.2118/193596-MS","url":null,"abstract":"\u0000 Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.\u0000 This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.\u0000 Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.\u0000 This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"137 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75492278","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Guannan Deng, A. Kan, Fangfu Zhang, A. Lu, M. Tomson
In this work a new laser-hydrothermal apparatus is designed to evaluate nucleation of scale minerals at temperature up to 250°C, its reliability is proven by measuring induction time data of barite from 90°C to 250°C at various Saturation index (SI) values, with the objective that such a design would contribute to the scale-related research at extreme temperature. Background solution (e.g. 1m NaCl) in a borosilicate glass bottle was placed inside a hydrothermal reactor. GC oven was used for temperature control and a modified Nd-Fe-B magnetic stirrer under the oven was used for stirring. A PFA tubing was selected to be the part with contact with solution for corrosion control. Using a 0.5 ml sample loop in two separate 6-ways switch valves, Ba2+ and SO42-concentrated solutions were simultaneously injected into a background solution. After supersaturation was initiated, a laser beam penetrated through the sight glasses installed on the both sides of the reactor to record the turbidity change during the nucleation process. Induction time (tind) of Saturation index (SI) values from 0.34 to 1.02 was measured at temperatures from 90°C to 250°C. Data correlates well with data from previous laser test at 90°C in a regular beaker experiment. The induction time (tind), that is, how fast a supersaturated solution induces nucleation and crystal growth to form detectable turbidity, decrease with temperature at a fixed SI value. For example, tind of 93 minutes at 150°C decreases to about 2 minutes at 250°C under the the same SI value of 0.65, indicating that increasing temperature facilitates the nucleation process at certain supersaturation levels. This temperature impact can be attributed both by thermodynamics and kinectic aspects.
{"title":"Novel Laser-Hydrothermal Apparatus for Nucleation and Inhibition Study of Scale Minerals at Temperatures up to 250°C","authors":"Guannan Deng, A. Kan, Fangfu Zhang, A. Lu, M. Tomson","doi":"10.2118/193556-MS","DOIUrl":"https://doi.org/10.2118/193556-MS","url":null,"abstract":"\u0000 In this work a new laser-hydrothermal apparatus is designed to evaluate nucleation of scale minerals at temperature up to 250°C, its reliability is proven by measuring induction time data of barite from 90°C to 250°C at various Saturation index (SI) values, with the objective that such a design would contribute to the scale-related research at extreme temperature.\u0000 Background solution (e.g. 1m NaCl) in a borosilicate glass bottle was placed inside a hydrothermal reactor. GC oven was used for temperature control and a modified Nd-Fe-B magnetic stirrer under the oven was used for stirring. A PFA tubing was selected to be the part with contact with solution for corrosion control. Using a 0.5 ml sample loop in two separate 6-ways switch valves, Ba2+ and SO42-concentrated solutions were simultaneously injected into a background solution. After supersaturation was initiated, a laser beam penetrated through the sight glasses installed on the both sides of the reactor to record the turbidity change during the nucleation process.\u0000 Induction time (tind) of Saturation index (SI) values from 0.34 to 1.02 was measured at temperatures from 90°C to 250°C. Data correlates well with data from previous laser test at 90°C in a regular beaker experiment. The induction time (tind), that is, how fast a supersaturated solution induces nucleation and crystal growth to form detectable turbidity, decrease with temperature at a fixed SI value. For example, tind of 93 minutes at 150°C decreases to about 2 minutes at 250°C under the the same SI value of 0.65, indicating that increasing temperature facilitates the nucleation process at certain supersaturation levels. This temperature impact can be attributed both by thermodynamics and kinectic aspects.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74781280","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}
Olivia Arends, B. Seymour, B. Benko, M. Elshahed, Lynn Yakoweshen, Sangeeta Ganguly-Mink
Microbial-induced problems in oil and gas incur high costs and cause severe environmental and safety concerns. Most of these problems are directly caused by surface-adhered bacteria colonies known as biofilms. Distinct populations of bacteria within a biofilm can symbiotically alter surrounding conditions that favor proliferation to the extent that leads to corrosion, plugging, and H2S souring. Biocides are antimicrobial products used to eliminate and prevent bacterial growth. The purpose of this initial study is to measure performance of biocides against anaerobic planktonic and sessile bacteria. The three anaerobic conditions tested were biocide performance against planktonic bacteria, against established biofilm, and inhibition of biofilm growth. Biocides containing two types of quaternary ammonium compounds and blends with glutaraldehyde were evaluated against sulfate reducing bacteria (SRB) and acid producing bacteria (APB) in both planktonkic and sessile forms. As expected, all of the biocides tested were effective against planktonic bacteria. Quaternary type biocides were found to be particularly effective at controlling sessile anaerobes. Surprisingly, the addition of glutaraldehyde did not appear to provide synergistic benefits and actually had a negative dilutory effect on the performance against biofilms. In all cases, dialkyl dimethyl ammonium chloride (DDAC) was the most efficient biocide in controlling all bacterial forms tested, both planktonic and sessile.
{"title":"An Ounce of Prevention is Worth a Pound of Biofilm Mitigation","authors":"Olivia Arends, B. Seymour, B. Benko, M. Elshahed, Lynn Yakoweshen, Sangeeta Ganguly-Mink","doi":"10.2118/193598-MS","DOIUrl":"https://doi.org/10.2118/193598-MS","url":null,"abstract":"\u0000 Microbial-induced problems in oil and gas incur high costs and cause severe environmental and safety concerns. Most of these problems are directly caused by surface-adhered bacteria colonies known as biofilms. Distinct populations of bacteria within a biofilm can symbiotically alter surrounding conditions that favor proliferation to the extent that leads to corrosion, plugging, and H2S souring. Biocides are antimicrobial products used to eliminate and prevent bacterial growth. The purpose of this initial study is to measure performance of biocides against anaerobic planktonic and sessile bacteria. The three anaerobic conditions tested were biocide performance against planktonic bacteria, against established biofilm, and inhibition of biofilm growth.\u0000 Biocides containing two types of quaternary ammonium compounds and blends with glutaraldehyde were evaluated against sulfate reducing bacteria (SRB) and acid producing bacteria (APB) in both planktonkic and sessile forms. As expected, all of the biocides tested were effective against planktonic bacteria. Quaternary type biocides were found to be particularly effective at controlling sessile anaerobes. Surprisingly, the addition of glutaraldehyde did not appear to provide synergistic benefits and actually had a negative dilutory effect on the performance against biofilms. In all cases, dialkyl dimethyl ammonium chloride (DDAC) was the most efficient biocide in controlling all bacterial forms tested, both planktonic and sessile.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76817207","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}
The optimum design of matrix acidizing treatments in carbonate reservoirs requires accurate modeling of wormhole propagation. While there are several wormhole correlation models available, most are developed based on small core scale experiments, and result in significant deviation when upscaled to field treatment design. There also exists simulation models (e.g. Two-Scale Continuum or Pore Network models). These models are not practical for field design because of the extensive computation effort involved. Large variations in the wormholing behavior are observed in laboratory experiments using different core sizes and geometries (radial flow versus linear flow). This variation is not captured in the previous models. This work proposes a new multiscale wormhole model that represents the physics of wormholing behavior in matrix acidizing of carbonates both at core and field scales. The derivation of the new semi-empirical model is formulated to represent the experimental data for different core dimensions and flow geometries, as well as field results. In core flooding experiments with different core sizes, the obtained pore volumes to breakthrough and optimal injection velocity are different for each core size. The same behavior is observed in numerical simulations using the Two-Scale Continuum model. That behavior is correctly calculated with the proposed model, which accounts for the dimensions in a function with dependence of the correlation parameters on the wormholed region scale and geometry. Upscaling procedures to linear, radial, elliptical, spherical, and ellipsoidal geometries are presented. The model's results are validated by the Two-Scale Continuum numerical simulations for both linear and radial flow and verified with experimental results with different core sizes and geometries (both linear and radial flow). We further developed the model for field application, and procedure of using the model is illustrated in the paper. The different flow geometries allow predicting the acidizing behavior in common completions, such as openhole, cased and perforated, and limited entry. The model prediction compares very well to the outcome of field cases. The new model reproduces the fractal behavior of the dominant wormhole growth above optimal injection rate, and predicts the injection pressure dependence on time as measured experimentally. The model correctly captured the physics of wormhole propagation phenomenon.
{"title":"A New Up-Scaled Wormhole Model Grounded on Experimental Results and in 2-Scale Continuum Simulations","authors":"M. Schwalbert, A. Hill, D. Zhu","doi":"10.2118/193616-MS","DOIUrl":"https://doi.org/10.2118/193616-MS","url":null,"abstract":"\u0000 The optimum design of matrix acidizing treatments in carbonate reservoirs requires accurate modeling of wormhole propagation. While there are several wormhole correlation models available, most are developed based on small core scale experiments, and result in significant deviation when upscaled to field treatment design. There also exists simulation models (e.g. Two-Scale Continuum or Pore Network models). These models are not practical for field design because of the extensive computation effort involved. Large variations in the wormholing behavior are observed in laboratory experiments using different core sizes and geometries (radial flow versus linear flow). This variation is not captured in the previous models. This work proposes a new multiscale wormhole model that represents the physics of wormholing behavior in matrix acidizing of carbonates both at core and field scales.\u0000 The derivation of the new semi-empirical model is formulated to represent the experimental data for different core dimensions and flow geometries, as well as field results. In core flooding experiments with different core sizes, the obtained pore volumes to breakthrough and optimal injection velocity are different for each core size. The same behavior is observed in numerical simulations using the Two-Scale Continuum model. That behavior is correctly calculated with the proposed model, which accounts for the dimensions in a function with dependence of the correlation parameters on the wormholed region scale and geometry. Upscaling procedures to linear, radial, elliptical, spherical, and ellipsoidal geometries are presented.\u0000 The model's results are validated by the Two-Scale Continuum numerical simulations for both linear and radial flow and verified with experimental results with different core sizes and geometries (both linear and radial flow). We further developed the model for field application, and procedure of using the model is illustrated in the paper. The different flow geometries allow predicting the acidizing behavior in common completions, such as openhole, cased and perforated, and limited entry. The model prediction compares very well to the outcome of field cases.\u0000 The new model reproduces the fractal behavior of the dominant wormhole growth above optimal injection rate, and predicts the injection pressure dependence on time as measured experimentally. The model correctly captured the physics of wormhole propagation phenomenon.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"426 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81198009","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}
Methods currently used to evaluate laboratory performance of asphaltenes inhibitors are non-optimal because the conditions used are so far from those prevailing in the field, leading to incorrect assessment of dose rates or even selection of chemicals that may not be beneficial at all. We present a dynamic flow test method for asphaltenes risk assessment and inhibitor qualification that uses field-representative temperature, pressure and fluid dynamics to enable successful correlation with field behaviour. This paper discusses the most commonly used laboratory test methods for asphaltenes testing and proposes a new dynamic flow method that offers a significant improvement over other widely-used techniques. Reconditioned dead crude oil is co-injected with n-heptane through a steel capillary and an inline filter. Differential pressures are recorded to monitor the extent of asphaltenes precipitation and deposition. We highlight key parameters that should be optimised to ensure that chemical performance is tested against the actual functionality required in the field and under conditions that are as representative as practicable. We present a case study describing the use of the dynamic flow test equipment to assess asphaltenes deposition risk and to qualify asphaltenes inhibitors for field application. We demonstrate that the method is able to rank chemicals for performance at inhibiting deposition under flowing conditions and at more field-representative temperature and pressure, with much lower percentages of n-heptane than required for conventional dispersancy testing. We discuss the effect of critical parameters affecting the extent of asphaltenes deposition. Fluid dynamics are recognised to play a key role in asphaltenes deposition in the field, not least, because at higher wall velocities the erosive force acting on field deposits is high enough to limit further growth and steady state can be reached. Flowing tests were conducted under a number of fluid-dynamic regimes in which asphaltenic crude oil was destabilised by addition of n-heptane. The effects of wall shear stress, wall velocity, residence time, and other factors were evaluated upon asphaltenes deposition in a steel capillary and upon bulk precipitation by subsequent filtration. The results obtained from laboratory tests correlate well with field observations and demonstrate that flow regimes in laboratory tests can approach those occurring in the field. This paper presents the development of a new laboratory test method utilising dead crude both for asphaltenes risk assessment and inhibitor qualification that offers significantly improved correlation with field behaviour over conventional dispersancy testing, yet remains much more cost effective than labour-intensive autoclave testing utilising live fluids. When considering asphaltenes risk analysis the approach also allows for deposition vs. precipitation to be examined under field realistic conditions, and we demonstrate how
{"title":"Asphaltenes Risk Assessment and Mitigation – Designing Appropriate Laboratory Test Protocols","authors":"A. R. Farrell, B. Martin, D. Frigo, G. Graham","doi":"10.2118/193560-MS","DOIUrl":"https://doi.org/10.2118/193560-MS","url":null,"abstract":"\u0000 Methods currently used to evaluate laboratory performance of asphaltenes inhibitors are non-optimal because the conditions used are so far from those prevailing in the field, leading to incorrect assessment of dose rates or even selection of chemicals that may not be beneficial at all. We present a dynamic flow test method for asphaltenes risk assessment and inhibitor qualification that uses field-representative temperature, pressure and fluid dynamics to enable successful correlation with field behaviour.\u0000 This paper discusses the most commonly used laboratory test methods for asphaltenes testing and proposes a new dynamic flow method that offers a significant improvement over other widely-used techniques. Reconditioned dead crude oil is co-injected with n-heptane through a steel capillary and an inline filter. Differential pressures are recorded to monitor the extent of asphaltenes precipitation and deposition. We highlight key parameters that should be optimised to ensure that chemical performance is tested against the actual functionality required in the field and under conditions that are as representative as practicable.\u0000 We present a case study describing the use of the dynamic flow test equipment to assess asphaltenes deposition risk and to qualify asphaltenes inhibitors for field application. We demonstrate that the method is able to rank chemicals for performance at inhibiting deposition under flowing conditions and at more field-representative temperature and pressure, with much lower percentages of n-heptane than required for conventional dispersancy testing.\u0000 We discuss the effect of critical parameters affecting the extent of asphaltenes deposition. Fluid dynamics are recognised to play a key role in asphaltenes deposition in the field, not least, because at higher wall velocities the erosive force acting on field deposits is high enough to limit further growth and steady state can be reached. Flowing tests were conducted under a number of fluid-dynamic regimes in which asphaltenic crude oil was destabilised by addition of n-heptane. The effects of wall shear stress, wall velocity, residence time, and other factors were evaluated upon asphaltenes deposition in a steel capillary and upon bulk precipitation by subsequent filtration. The results obtained from laboratory tests correlate well with field observations and demonstrate that flow regimes in laboratory tests can approach those occurring in the field.\u0000 This paper presents the development of a new laboratory test method utilising dead crude both for asphaltenes risk assessment and inhibitor qualification that offers significantly improved correlation with field behaviour over conventional dispersancy testing, yet remains much more cost effective than labour-intensive autoclave testing utilising live fluids. When considering asphaltenes risk analysis the approach also allows for deposition vs. precipitation to be examined under field realistic conditions, and we demonstrate how","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"133 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80019623","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}
Amanda Miller, Rashod Smith, B. Dufresne, A. Mahmoudkhani
Traditional test methods to evaluate dispersion and inhibition of paraffin wax, which are mainly based on wax gelation and deposition, often fail to distinguish and differentiate between classes of chemistries at a reasonable resolution. Recommended products based on such lab screenings sometimes have a difficult time proving success in the field. The rush for oil production from unconventional shale plays in North America create a need for quick and elaborate testing to effectively evaluate new products for prevention and remediation of known paraffin wax issues. This paper will present a progress made in this area. For our studies a model oil system was used, which consists of field wax deposit dissolved in kerosene. Testing with a model oil allowed us to focus on the chemistries that are effective against paraffin chains known to cause issues. Several different testing conditions were used to push the ability of the chemistries to function. Light scattering was used to monitor transition from turbidity to sedimentation of paraffin wax from bulk solution under static or dynamic conditions. A total of twelve compounds from three classes of polymers and three classes of surfactants were used in treatment of these oil systems. With this new lab testing methodology, we have been able to discover new insights on the chemistries used for paraffin wax dispersion and inhibition. In contrast to methods which only measure the end point, light scattering and transmission methodology provides system details at time intervals of 30 sec or higher. The method also allowed us to differentiate chemistries based on their impact on the separation index and sedimentation rate of targeted paraffin chains under stressed conditions by forced precipitation. It was found that certain classes of chemistries are more suited for dispersion and inhibition of waxy condensates once system passed the critical point, while others fail over time. This new approach is fast and versatile and must be used as part of a suite of lab and field screenings for product development and recommendation. New methodology based on light scattering and transmission of oil systems can provide details not seen before on colloidal stability or instability of waxy crudes under stressed conditions. The method gives an even greater insight to how different chemistries function to mitigate known paraffin issues. Quantitative and reproducible data are obtained allowing faster screening of various chemistries and enhancing product development for new and aging fields.
{"title":"Out with the Old: Developing a New Test Methodology for Paraffin Wax Dispersion and Inhibition Testing","authors":"Amanda Miller, Rashod Smith, B. Dufresne, A. Mahmoudkhani","doi":"10.2118/193552-MS","DOIUrl":"https://doi.org/10.2118/193552-MS","url":null,"abstract":"\u0000 Traditional test methods to evaluate dispersion and inhibition of paraffin wax, which are mainly based on wax gelation and deposition, often fail to distinguish and differentiate between classes of chemistries at a reasonable resolution. Recommended products based on such lab screenings sometimes have a difficult time proving success in the field. The rush for oil production from unconventional shale plays in North America create a need for quick and elaborate testing to effectively evaluate new products for prevention and remediation of known paraffin wax issues. This paper will present a progress made in this area.\u0000 For our studies a model oil system was used, which consists of field wax deposit dissolved in kerosene. Testing with a model oil allowed us to focus on the chemistries that are effective against paraffin chains known to cause issues. Several different testing conditions were used to push the ability of the chemistries to function. Light scattering was used to monitor transition from turbidity to sedimentation of paraffin wax from bulk solution under static or dynamic conditions. A total of twelve compounds from three classes of polymers and three classes of surfactants were used in treatment of these oil systems.\u0000 With this new lab testing methodology, we have been able to discover new insights on the chemistries used for paraffin wax dispersion and inhibition. In contrast to methods which only measure the end point, light scattering and transmission methodology provides system details at time intervals of 30 sec or higher. The method also allowed us to differentiate chemistries based on their impact on the separation index and sedimentation rate of targeted paraffin chains under stressed conditions by forced precipitation. It was found that certain classes of chemistries are more suited for dispersion and inhibition of waxy condensates once system passed the critical point, while others fail over time. This new approach is fast and versatile and must be used as part of a suite of lab and field screenings for product development and recommendation.\u0000 New methodology based on light scattering and transmission of oil systems can provide details not seen before on colloidal stability or instability of waxy crudes under stressed conditions. The method gives an even greater insight to how different chemistries function to mitigate known paraffin issues. Quantitative and reproducible data are obtained allowing faster screening of various chemistries and enhancing product development for new and aging fields.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"90 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76043950","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}
Thu T. Nguyen, A. Raj, R. Rommerskirchen, Jorge Fernandez
Low steam viscosity during steam injection can cause steam override and channeling issues for heavy oil recovery, resulting in high operating cost and low oil recovery. One of the common methods to increase the viscosity of steam is by co-injecting surfactants that generate stable foams with steam. The objective of this research is to develop structure-property relationships for surfactants in order to identify surfactant candidates as the steam foam additives for heavy oil recovery. In this study, alkyl propoxy ethoxy ether carboxylate (alkyl PO EO ECA) surfactants were evaluated. Surfactant solutions at 1 wt% prepared in 1 wt% NaCl were aged at up to 250 °C in Parr reactors for up to 2 weeks. The degradation of the surfactants was quantified based on High Performance Liquid Chromatography profiles of the surfactants before and after the aging process. The foaming performance of the surfactants was evaluated at 1 wt% concentration at varied temperatures from 100 to 250 °C in a high temperature high pressure visual cell. Sand-packed columns were performed to evaluate the ability of the surfactant to increase the apparent viscosity of steam. The results showed that alkyl PO EO ECA surfactants exhibit excellent chemical stability at up to 250 °C. However, the chemical stability of these surfactants are dependent on the hydrophobe structure as well as the numbers of PO and EO units of the surfactants. Among the studied surfactants, only ECA surfactants with specific structures were able to generate stable foam at 250 °C. It was found that the ECA surfactants with both PO and EO units and a long branched hydrophobe demonstrated to be excellent foaming agents that were able to increase the apparent viscosity of steam by three orders of magnitude at 250 °C in sand-pack columns. In the presence of bitumen, these surfactants were able to increase the steam apparent viscosity by two orders of magnitude. This increase in the steam apparent viscosity is sufficient to overcome the steam override and channeling during steam injection. Past research has randomly identified some sulfonate and ether carboxylate surfactants as foaming agents for steam EOR processes. This work, however, evaluated these surfactants systematically in order to develop the structure-property relationships that can be used to optimize surfactants as steam foaming agents for thermal EOR processes at up to 250 °C.
注汽过程中的低蒸汽粘度会导致稠油开采过程中的蒸汽覆盖和窜流问题，导致作业成本高，采收率低。增加蒸汽粘度的常用方法之一是通过与蒸汽共同注入表面活性剂来产生稳定的泡沫。本研究的目的是建立表面活性剂的结构-性能关系，以确定表面活性剂作为稠油开采蒸汽泡沫添加剂的候选表面活性剂。对烷基丙氧基乙氧基醚羧酸酯(烷基PO EO ECA)表面活性剂进行了评价。在1wt %的NaCl中制备1wt %的表面活性剂溶液，在Parr反应器中在高达250°C的温度下时效长达2周。利用高效液相色谱法测定老化前后表面活性剂的降解情况。在100 ~ 250℃的高温高压视觉池中，以1 wt%的浓度评价表面活性剂的发泡性能。用砂填充柱来评价表面活性剂提高蒸汽表观粘度的能力。结果表明，烷基PO EO ECA表面活性剂在高达250℃的温度下具有优异的化学稳定性。然而，这些表面活性剂的化学稳定性取决于疏水结构以及表面活性剂的PO和EO单元的数量。在所研究的表面活性剂中，只有具有特定结构的ECA表面活性剂能够在250℃下产生稳定的泡沫。研究发现，同时具有PO和EO单元和长支疏水剂的ECA表面活性剂是优异的发泡剂，能够在250°C的砂填料柱中将蒸汽的表观粘度提高三个数量级。在沥青存在的情况下，这些表面活性剂能够将蒸汽表观粘度提高两个数量级。蒸汽表观粘度的增加足以克服注汽过程中的蒸汽覆盖和窜流问题。过去的研究随机确定了一些磺酸盐和醚羧酸盐表面活性剂作为蒸汽提高采收率过程的发泡剂。然而，这项工作系统地评估了这些表面活性剂，以建立结构-性能关系，可用于优化表面活性剂作为蒸汽发泡剂，用于高达250°C的热采收率过程。
{"title":"Development of Structure-Property Relationships for Steam Foam Additives for Heavy Oil Recovery","authors":"Thu T. Nguyen, A. Raj, R. Rommerskirchen, Jorge Fernandez","doi":"10.2118/193634-MS","DOIUrl":"https://doi.org/10.2118/193634-MS","url":null,"abstract":"\u0000 Low steam viscosity during steam injection can cause steam override and channeling issues for heavy oil recovery, resulting in high operating cost and low oil recovery. One of the common methods to increase the viscosity of steam is by co-injecting surfactants that generate stable foams with steam. The objective of this research is to develop structure-property relationships for surfactants in order to identify surfactant candidates as the steam foam additives for heavy oil recovery.\u0000 In this study, alkyl propoxy ethoxy ether carboxylate (alkyl PO EO ECA) surfactants were evaluated. Surfactant solutions at 1 wt% prepared in 1 wt% NaCl were aged at up to 250 °C in Parr reactors for up to 2 weeks. The degradation of the surfactants was quantified based on High Performance Liquid Chromatography profiles of the surfactants before and after the aging process. The foaming performance of the surfactants was evaluated at 1 wt% concentration at varied temperatures from 100 to 250 °C in a high temperature high pressure visual cell. Sand-packed columns were performed to evaluate the ability of the surfactant to increase the apparent viscosity of steam.\u0000 The results showed that alkyl PO EO ECA surfactants exhibit excellent chemical stability at up to 250 °C. However, the chemical stability of these surfactants are dependent on the hydrophobe structure as well as the numbers of PO and EO units of the surfactants. Among the studied surfactants, only ECA surfactants with specific structures were able to generate stable foam at 250 °C. It was found that the ECA surfactants with both PO and EO units and a long branched hydrophobe demonstrated to be excellent foaming agents that were able to increase the apparent viscosity of steam by three orders of magnitude at 250 °C in sand-pack columns. In the presence of bitumen, these surfactants were able to increase the steam apparent viscosity by two orders of magnitude. This increase in the steam apparent viscosity is sufficient to overcome the steam override and channeling during steam injection.\u0000 Past research has randomly identified some sulfonate and ether carboxylate surfactants as foaming agents for steam EOR processes. This work, however, evaluated these surfactants systematically in order to develop the structure-property relationships that can be used to optimize surfactants as steam foaming agents for thermal EOR processes at up to 250 °C.","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":"89709884","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}
Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (e.g., CO2 WAG) etc. However, the improved oil recovery is often accompanied by physical and chemical changes in the produced fluids that cause many production-chemistry (PC)-related challenges when fluids subsequently arrive in the production system, including exacerbation of scale and naphthenates deposition, carboxylate deposits associated with injected polymer, enhanced corrosion and separation issues, etc. Understanding and predicting the production chemistry challenges at producers are further complicated by chemical changes as the fluids propagate through the reservoir such as reaction with reservoir formation minerals, chemical retention, chemical degradation and hydrolysis, etc. More importantly the implications for the production system and processing facilities are not always accounted for and proactively managed. The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance per se as well as retention onto rock during squeeze treatment. Also illustrated are the risk of carboxylate-based deposit derived from polymer flood, and the phenomenon of carboxylate-based solids and soaps, which can exacerbate the separation of an already highly challenging system. The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.
{"title":"Production Chemistry Issues and Solutions Associated with Chemical EOR","authors":"G. Graham, D. Frigo","doi":"10.2118/193568-MS","DOIUrl":"https://doi.org/10.2118/193568-MS","url":null,"abstract":"\u0000 Chemical EOR is an increasingly employed approach used to enhance oil recovery by combining changes in fluids mobility, macroscopic sweep, interfacial tension, etc. to essentially improve, or extend the economic life of a water flood. It includes flooding with polymer, surfactant, alkaline/surfactant, alkaline-surfactant-polymer (ASP), CO2 and / or other miscible gases which is often combined with waterflood (e.g., CO2 WAG) etc. However, the improved oil recovery is often accompanied by physical and chemical changes in the produced fluids that cause many production-chemistry (PC)-related challenges when fluids subsequently arrive in the production system, including exacerbation of scale and naphthenates deposition, carboxylate deposits associated with injected polymer, enhanced corrosion and separation issues, etc. Understanding and predicting the production chemistry challenges at producers are further complicated by chemical changes as the fluids propagate through the reservoir such as reaction with reservoir formation minerals, chemical retention, chemical degradation and hydrolysis, etc. More importantly the implications for the production system and processing facilities are not always accounted for and proactively managed.\u0000 The paper evaluates the main chemical changes that occur in the system for each EOR approach –– and shows how these changes, including in situ reservoir reactions and the stability/instability of the EOR packages themselves can exacerbate a range of PC-related challenges especially when considering the likely production of up to three different fluids: formation water, the EOR flood medium and any previous flood water from previous secondary recovery\u0000 The paper includes modelling results, laboratory results to validate model predictions as well as examples from field case studies to illustrate the impact of the chemical changes referred to above. Specific highlights include the impact of the use of either high- or low-pH EOR fluids on scale control, corrosion control and asphaltenes control; for scale it examines both inhibitor performance per se as well as retention onto rock during squeeze treatment. Also illustrated are the risk of carboxylate-based deposit derived from polymer flood, and the phenomenon of carboxylate-based solids and soaps, which can exacerbate the separation of an already highly challenging system.\u0000 The overall conclusion is that chemical EOR can have significant impact on PC and that these should not just be considered at the design stage and not just for the injection system but also to take into account the impact these may have on production wells following breakthrough of flood waters, showing that essentially each new or exacerbated PC issues can be predicted or at least anticipated with the required degree of confidence before implementation of EOR.","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":"90817200","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}
Accurate scale prediction modelling is only possible when reliable mineral solubility data are available under the required conditions. It is recognised that the relative paucity of high pressure, high temperature (HPHT) solubility data can result in inaccurate predictions as current models extrapolate from data obtained under more conventional conditions. This paper describes the generation of additional fundamental solubility data under HPHT conditions and comparison of the obtained values with several existing models. A purpose-built laboratory test rig capable of making mineral solubility measurements up to 250 °C (480 °F) and up to 30,000 psi has been used in this work. Experimental solubility data have been generated for calcium sulphate at different temperatures and the methodology has been investigated to ensure that equilibrium conditions have been reached. In this work, barium sulphate solubility data have also been generated at conditions up to 200 °C (390 °F) and 19,000 psi. Notably, the solubilities have been determined in the presence of relatively high concentrations of additional ions, e.g., calcium, as it was recognised that available data were limited for more oilfield-representative brine compositions from HPHT reservoirs. The data generated were also compared against solubility predictions for a range of industry models to assess their accuracy in these circumstances. The results obtained for calcium sulphate solubility indicate the importance of validating the test methodology, not just for each mineral, but also under the required temperature and pressure conditions, to verify that equilibrium solubility conditions have been achieved. Barium sulphate solubility increases with the addition of other divalent ions but the extent of the increase is at present not accurately predicted by existing scale prediction models at HPHT conditions. In some cases, the predicted barium sulphate solubility was up to three times greater than the experimentally determined value. It is apparent that there is considerable scope for improvement of scale prediction models under HPHT conditions particularly in complex brine systems and that further fundamental solubility data are required to facilitate this. This paper provides additional data for mineral solubility under HPHT conditions but, more importantly, shows data for complex brines that are more representative of those produced in oilfields. The work further demonstrates the limitations of existing scale prediction modelling software under HPHT conditions, particularly in the presence of other divalent ions, and illustrates areas where additional data and model development is critical to enable more accurate modelling of scale risk under these conditions.
{"title":"Scale Prediction and Mineral Solubility Under HPHT Conditions","authors":"D. Nichols, N. Goodwin, G. Graham, D. Frigo","doi":"10.2118/193564-MS","DOIUrl":"https://doi.org/10.2118/193564-MS","url":null,"abstract":"\u0000 Accurate scale prediction modelling is only possible when reliable mineral solubility data are available under the required conditions. It is recognised that the relative paucity of high pressure, high temperature (HPHT) solubility data can result in inaccurate predictions as current models extrapolate from data obtained under more conventional conditions. This paper describes the generation of additional fundamental solubility data under HPHT conditions and comparison of the obtained values with several existing models.\u0000 A purpose-built laboratory test rig capable of making mineral solubility measurements up to 250 °C (480 °F) and up to 30,000 psi has been used in this work. Experimental solubility data have been generated for calcium sulphate at different temperatures and the methodology has been investigated to ensure that equilibrium conditions have been reached. In this work, barium sulphate solubility data have also been generated at conditions up to 200 °C (390 °F) and 19,000 psi. Notably, the solubilities have been determined in the presence of relatively high concentrations of additional ions, e.g., calcium, as it was recognised that available data were limited for more oilfield-representative brine compositions from HPHT reservoirs. The data generated were also compared against solubility predictions for a range of industry models to assess their accuracy in these circumstances.\u0000 The results obtained for calcium sulphate solubility indicate the importance of validating the test methodology, not just for each mineral, but also under the required temperature and pressure conditions, to verify that equilibrium solubility conditions have been achieved. Barium sulphate solubility increases with the addition of other divalent ions but the extent of the increase is at present not accurately predicted by existing scale prediction models at HPHT conditions. In some cases, the predicted barium sulphate solubility was up to three times greater than the experimentally determined value. It is apparent that there is considerable scope for improvement of scale prediction models under HPHT conditions particularly in complex brine systems and that further fundamental solubility data are required to facilitate this.\u0000 This paper provides additional data for mineral solubility under HPHT conditions but, more importantly, shows data for complex brines that are more representative of those produced in oilfields. The work further demonstrates the limitations of existing scale prediction modelling software under HPHT conditions, particularly in the presence of other divalent ions, and illustrates areas where additional data and model development is critical to enable more accurate modelling of scale risk under these conditions.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83269306","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}
Ferm Paul, Germer Jeff, H. Kurt, H. Stuart, R. Andrew, Sanders Jannifer, R. Klin, T. John, Wolf Nick, Zhang Lei
The controlled release of scale inhibitors (SI) and other treatment chemicals in the near-wellbore region is a key strategy to improving water management and extended well production. In addition, during some completion and stimulation operations, it is desired that robust particles providing controlled release be placed in gravel and sand packs. A novel controlled release scale inhibitor particle is presented which provides beneficial properties due to its unique chemistry and polymer processing methods. This technology provides extended feedback of scale inhibitor with tunable release rates.
{"title":"Cross-Linked Polymeric Controlled Release Particles for Inorganic Scale Inhibition","authors":"Ferm Paul, Germer Jeff, H. Kurt, H. Stuart, R. Andrew, Sanders Jannifer, R. Klin, T. John, Wolf Nick, Zhang Lei","doi":"10.2118/193557-MS","DOIUrl":"https://doi.org/10.2118/193557-MS","url":null,"abstract":"\u0000 The controlled release of scale inhibitors (SI) and other treatment chemicals in the near-wellbore region is a key strategy to improving water management and extended well production. In addition, during some completion and stimulation operations, it is desired that robust particles providing controlled release be placed in gravel and sand packs. A novel controlled release scale inhibitor particle is presented which provides beneficial properties due to its unique chemistry and polymer processing methods. This technology provides extended feedback of scale inhibitor with tunable release rates.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"252 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86566972","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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