Haiping Lu, Bethanni Mccabe, Johnathon Brooks, S. Heath, Shane Stevens
As the oil industry continues to operate in more complex and ultrahigh temperature environments scale control becomes an ever increasing challenge. Scale inhibitors are being pushed to their operational limits and start to lose their efficiency against both calcium carbonate and calcium sulphate scales at >400°F. It is therefore essential to develop the next generation scale inhibitor to work effectively against scale in harsh, high temperature environments such as steam floods and gas wells. In this study, details will be provided on the thermal stability test of a novel, biodegradable phosphonate scale inhibitor at temperatures 300°F and 400°F at two pH values, pH 4.0 and pH 6.0. Bottle tests on calcium carbonate and calcium sulfate were conducted with the thermal-aged phosphonate for their inhibition. Dynamic tube blocking tests were also conducted for calcium carbonate and calcium sulfate inhibition at 392°F to demonstrate the performance of the inhibitor. The new phosphonate scale inhibitor has also been designed to be biodegradable and it can be deployed by both continuous injection and scale squeeze treatment which is an advantage compared to polymers as they are often less suitable for high temperature scale squeeze treatments. Careful consideration was also given in the molecular design process for high calcium tolerance and details of brine compatibility at high temperature will be provided. This paper presents details of the evaluation of a biodegradable, thermally stable and calcium tolerant phosphonate scale inhibitor for both calcium sulphate and calcium carbonate scale control in ultrahigh temperature environments at ~400°F. In addition, the environmental test data will be discussed along with details of a field example of continuous downhole deployment of the new phosphonate scale inhibitor for calcium carbonate scale control in a high calcium brine (30,000 mg/L).
{"title":"A Novel Phosphonate Scale Inhibitor for Scale Control in Ultra High Temperature Environments","authors":"Haiping Lu, Bethanni Mccabe, Johnathon Brooks, S. Heath, Shane Stevens","doi":"10.2118/193554-MS","DOIUrl":"https://doi.org/10.2118/193554-MS","url":null,"abstract":"\u0000 As the oil industry continues to operate in more complex and ultrahigh temperature environments scale control becomes an ever increasing challenge. Scale inhibitors are being pushed to their operational limits and start to lose their efficiency against both calcium carbonate and calcium sulphate scales at >400°F. It is therefore essential to develop the next generation scale inhibitor to work effectively against scale in harsh, high temperature environments such as steam floods and gas wells.\u0000 In this study, details will be provided on the thermal stability test of a novel, biodegradable phosphonate scale inhibitor at temperatures 300°F and 400°F at two pH values, pH 4.0 and pH 6.0. Bottle tests on calcium carbonate and calcium sulfate were conducted with the thermal-aged phosphonate for their inhibition. Dynamic tube blocking tests were also conducted for calcium carbonate and calcium sulfate inhibition at 392°F to demonstrate the performance of the inhibitor.\u0000 The new phosphonate scale inhibitor has also been designed to be biodegradable and it can be deployed by both continuous injection and scale squeeze treatment which is an advantage compared to polymers as they are often less suitable for high temperature scale squeeze treatments. Careful consideration was also given in the molecular design process for high calcium tolerance and details of brine compatibility at high temperature will be provided.\u0000 This paper presents details of the evaluation of a biodegradable, thermally stable and calcium tolerant phosphonate scale inhibitor for both calcium sulphate and calcium carbonate scale control in ultrahigh temperature environments at ~400°F. In addition, the environmental test data will be discussed along with details of a field example of continuous downhole deployment of the new phosphonate scale inhibitor for calcium carbonate scale control in a high calcium brine (30,000 mg/L).","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"96 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81888436","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}
Maintaining overall asphaltene stability is imperative for a successful flow assurance treatment program. However, complex interactions between the polar asphaltene fraction and other components in crude oil or reservoir minerals makes the stability assessment extremely challenging. These interactions can contribute towards the precipitation and subsequent deposition of unstable asphaltene clusters comprising of impurities such as paraffin, polar organics, and inorganic mineral composites. This study investigates the impact of inorganic salts and minerals on asphaltene stability and inhibitor performance efficiency. Four problematic crude oil samples having asphaltene deposition issue along with its field deposits were analyzed. Primary characterization of oil samples was conducted by measuring physicochemical properties. Crude oil and deposit samples were further evaluated by performing multiple compositional analyses like Fourier Transform InfraRed (FTIR) Spectroscopy, Carbon Chain Distribution (CCD), and X-Ray Fluorescence (XRF). Furthermore, asphaltene inhibitor performance efficiency was measured by carrying out both dispersion test analyses. Primary characterization of crude oil samples did not suggest any anomalous behavior indicative of unstable asphaltene fraction. However, the solid field deposition in the production and flow-lines were observed. Therefore, further analyses of the oil as well as the solid deposits was necessitated. The analyses revealed unusually high concentration of inorganic impurities co-precipitating out with the asphaltene fraction. In general, polar nature of asphaltene induces van der Waals force of attraction between permanent dipoles (Keesom), induced dipoles (London dispersion), and permanent with induced dipoles (Debye). Paraffin and polar organic fractions associate with asphaltene through van der Waals forces and reduces the active polar sites available for the inhibitor to interact with. Moreover, presence of ions within the salts and inorganic minerals introduce ion-ion or ion-dipole interactions, which are considerably stronger than the van der Waals forces. Thus, these interactions with ionic salts and minerals interfere with the inhibitor-asphaltene interactions to a greater extent and consequently reduces the inhibitor performance efficiency significantly within laboratory screening methods. This study, for the first time, highlights detailed contribution of impurities, specifically of ionic salts and minerals originated from drilling and completion fluids or reservoir minerals, on the overall asphaltene stability and inhibitor performance efficiency. The molecular forces arising due to co-precipitation of organic and inorganic minerals were observed to impact the asphaltene inhibitor performance considerably. Therefore, it is important to comprehend the compositional and elemental content of both crude oil and field deposit samples and accordingly select asphaltene testing methodology and modif
{"title":"Impact of Inorganic Salts and Minerals on Asphaltene Stability and Inhibitor Performance","authors":"A. Punase, J. I. Aguiar, A. Mahmoudkhani","doi":"10.2118/193559-MS","DOIUrl":"https://doi.org/10.2118/193559-MS","url":null,"abstract":"\u0000 Maintaining overall asphaltene stability is imperative for a successful flow assurance treatment program. However, complex interactions between the polar asphaltene fraction and other components in crude oil or reservoir minerals makes the stability assessment extremely challenging. These interactions can contribute towards the precipitation and subsequent deposition of unstable asphaltene clusters comprising of impurities such as paraffin, polar organics, and inorganic mineral composites. This study investigates the impact of inorganic salts and minerals on asphaltene stability and inhibitor performance efficiency.\u0000 Four problematic crude oil samples having asphaltene deposition issue along with its field deposits were analyzed. Primary characterization of oil samples was conducted by measuring physicochemical properties. Crude oil and deposit samples were further evaluated by performing multiple compositional analyses like Fourier Transform InfraRed (FTIR) Spectroscopy, Carbon Chain Distribution (CCD), and X-Ray Fluorescence (XRF). Furthermore, asphaltene inhibitor performance efficiency was measured by carrying out both dispersion test analyses.\u0000 Primary characterization of crude oil samples did not suggest any anomalous behavior indicative of unstable asphaltene fraction. However, the solid field deposition in the production and flow-lines were observed. Therefore, further analyses of the oil as well as the solid deposits was necessitated. The analyses revealed unusually high concentration of inorganic impurities co-precipitating out with the asphaltene fraction. In general, polar nature of asphaltene induces van der Waals force of attraction between permanent dipoles (Keesom), induced dipoles (London dispersion), and permanent with induced dipoles (Debye). Paraffin and polar organic fractions associate with asphaltene through van der Waals forces and reduces the active polar sites available for the inhibitor to interact with. Moreover, presence of ions within the salts and inorganic minerals introduce ion-ion or ion-dipole interactions, which are considerably stronger than the van der Waals forces. Thus, these interactions with ionic salts and minerals interfere with the inhibitor-asphaltene interactions to a greater extent and consequently reduces the inhibitor performance efficiency significantly within laboratory screening methods.\u0000 This study, for the first time, highlights detailed contribution of impurities, specifically of ionic salts and minerals originated from drilling and completion fluids or reservoir minerals, on the overall asphaltene stability and inhibitor performance efficiency. The molecular forces arising due to co-precipitation of organic and inorganic minerals were observed to impact the asphaltene inhibitor performance considerably. Therefore, it is important to comprehend the compositional and elemental content of both crude oil and field deposit samples and accordingly select asphaltene testing methodology and modif","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"114 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91364204","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}
Preformed Particle Gel (PPG) is an appropriate solution for conformance control and managing water production in low permeable reservoirs. Rheological behavior evaluation of these deformable particles is a key factor in designing composition to achieve the best conformance control treatment due to the viscoelastic behavior of these particles along with their swelling. The purpose of this paper is to evaluate the network parameters of PPGs through swelling tests, rheology and determining its role in maintaining their structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and Cr(OAc)3 as copolymer and crosslinker, respectively. The characterization of these hydrogels was performed using Scanning Electron Micrographs (SEM), Electron Dispersion X-ray analysis (EDX), Environmental Scanning Electron Microscopy (ESEM), ThermoGravimetric Analysis (TGA), and Differential ThermoGravimetry (DTG). The correlation between reaction conditions and network parameters of polymer networks such as, molecular weight of the polymer chain between two neighboring crosslinks, crosslink density, and size fraction have been determined. The swelling of the hydrogels was found through the Fickian diffusion mechanism. In this case, the diffusion rate of water in the 3D structure of the hydrogel is less than the relaxation of the polymeric chain, resulting in a significant increase in the PPG particles volume. As PPG was invaded such as in the reservoir by formation water or oil, repeatedly, the sensitivity factor was measured to ensure the swelling in the electrolyte solution. Based on rheological tests, the dynamic modulus of the swelled PPG was strongly dependent on the concentration and consequently network parameters. Also, through the optimization of the network parameters, the appropriate composition from the point of view of strength (complex modulus of 4×104 Pa) and salt sensitivity of 0.5 was presented. In addition, the results of the TGA/DTG test demonstrated the thermal stability of the sample was in temperature range 245 to 340°C. The determination and analysis of the network parameter is the novel technique for predicting the hydrogel performance in porous media and investigating its strength under harsh reservoir conditions. In other words, determination of the network parameter can be a shortcut to ensure the success of the gel performance in porous media.
{"title":"Effect of Network Parameters of Preformed Particle Gel on Structural Strength for Water Management","authors":"M. Salehi, A. M. Moghadam, K. Jarrahian","doi":"10.2118/193631-MS","DOIUrl":"https://doi.org/10.2118/193631-MS","url":null,"abstract":"\u0000 Preformed Particle Gel (PPG) is an appropriate solution for conformance control and managing water production in low permeable reservoirs. Rheological behavior evaluation of these deformable particles is a key factor in designing composition to achieve the best conformance control treatment due to the viscoelastic behavior of these particles along with their swelling. The purpose of this paper is to evaluate the network parameters of PPGs through swelling tests, rheology and determining its role in maintaining their structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and Cr(OAc)3 as copolymer and crosslinker, respectively. The characterization of these hydrogels was performed using Scanning Electron Micrographs (SEM), Electron Dispersion X-ray analysis (EDX), Environmental Scanning Electron Microscopy (ESEM), ThermoGravimetric Analysis (TGA), and Differential ThermoGravimetry (DTG). The correlation between reaction conditions and network parameters of polymer networks such as, molecular weight of the polymer chain between two neighboring crosslinks, crosslink density, and size fraction have been determined. The swelling of the hydrogels was found through the Fickian diffusion mechanism. In this case, the diffusion rate of water in the 3D structure of the hydrogel is less than the relaxation of the polymeric chain, resulting in a significant increase in the PPG particles volume. As PPG was invaded such as in the reservoir by formation water or oil, repeatedly, the sensitivity factor was measured to ensure the swelling in the electrolyte solution. Based on rheological tests, the dynamic modulus of the swelled PPG was strongly dependent on the concentration and consequently network parameters. Also, through the optimization of the network parameters, the appropriate composition from the point of view of strength (complex modulus of 4×104 Pa) and salt sensitivity of 0.5 was presented. In addition, the results of the TGA/DTG test demonstrated the thermal stability of the sample was in temperature range 245 to 340°C. The determination and analysis of the network parameter is the novel technique for predicting the hydrogel performance in porous media and investigating its strength under harsh reservoir conditions. In other words, determination of the network parameter can be a shortcut to ensure the success of the gel performance in porous media.","PeriodicalId":11243,"journal":{"name":"Day 2 Tue, April 09, 2019","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-02-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86284252","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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