S. Murugesan, Radhika Suresh, V. Khabashesku, Qusai A. Darugar
A new method has been developed to differentiate and quantify the amount of primary amines through a simple chemical process. Colored cyclic adduct compounds are formed by reaction of selective chemicals with primary amine. This adduct formation is preferential to the primary amine, even in the presence of a mixture of secondary and tertiary amines. The adduct shows selective enhanced fluorescence emission at 475-nm wavelength under specific excitation with 420 nm. Due to enhanced fluorescence activity, quantification becomes possible, even below a 1-ppm concentration of specific primary amine. A chemical matrix, formulated with the mixture of different concentrations of primary, secondary and tertiary amines, helps to differentiate and quantify primary amines present in the mixture, even at lower concentrations. This method is validated under synthetic field brine conditions to detect and quantify primary amines towards field applications.
{"title":"Differentiation and Quantification of Corrosive Amines Through Simple Chemical Process","authors":"S. Murugesan, Radhika Suresh, V. Khabashesku, Qusai A. Darugar","doi":"10.2118/193614-MS","DOIUrl":"https://doi.org/10.2118/193614-MS","url":null,"abstract":"\u0000 A new method has been developed to differentiate and quantify the amount of primary amines through a simple chemical process. Colored cyclic adduct compounds are formed by reaction of selective chemicals with primary amine. This adduct formation is preferential to the primary amine, even in the presence of a mixture of secondary and tertiary amines. The adduct shows selective enhanced fluorescence emission at 475-nm wavelength under specific excitation with 420 nm. Due to enhanced fluorescence activity, quantification becomes possible, even below a 1-ppm concentration of specific primary amine. A chemical matrix, formulated with the mixture of different concentrations of primary, secondary and tertiary amines, helps to differentiate and quantify primary amines present in the mixture, even at lower concentrations. This method is validated under synthetic field brine conditions to detect and quantify primary amines towards field applications.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83421334","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. Paschoalino, Jon B Raymond, E. Sianawati, Veronica Silva
The performance of a new synergistic biocide combination based on glutaraldehyde and THNM (tris (hydroxymethyl) nitromethane) was extensively evaluated in laboratory trials using water samples from twenty-six Brazilian and Argentinian oilfields. The performance was ultimately validated in four field trials, two per country (A1, A2, B1, B2), over a three month duration. For laboratory tests, water samples were collected from numerous locations of the various oilfields and characterized/enumerated by serial dilution (SRB and APB bug bottles), ATP, and molecular biology techniques (NGS). Water and isolated indigenous SRB/APB from the most contaminated locations were used as the matrix and test inoculum for the biocide optimization tests. Numerous biocide systems, at total active ingredient concentrations ranging from 111 to 250 ppm, were evaluated by assessing the ability to rapidly kill the native organisms (2 hour contact time at room temperature) and protect the water from contamination over a prolonged time frame (≥7 days) under heat-aged conditions (60°C). Results demonstrated that glutaraldehyde/THNM provided the best performance in the majority of the samples evaluated and was therefore selected for performance evaluations in field tests owing to the enhanced performance of this particular treatment in the laboratory. Field trials were conducted by applying the lowest total biocide concentration that demonstrated a ≥ 4 log10 microbial reduction (in the laboratory studies) at various problematic field locations. All biocides were dosed as batch treatments 2-3 times per week (2-3 hours per treatment). Specifically, the co-dosed glutaraldehyde/THNM combination replaced incumbent treatments of either THPS or glutaraldehyde (batch dosed) in combination with a quaternary ammonium compound which was being applied by continuous injection: Field trial B1 – Results showed a significant reduction in bacterial counts at the farthest injection well (12 km from the point of biocide application). Total anaerobic bacteria levels were reduced from ~106 CFU/mL to less than 102 CFU/mL after 1 month treatment. Additionally, total biocide consumption was reduced by 24% as compared to the incumbent biocides traditionally applied. Field trial B2 – Following treatment of injection water, SRB results showed a reduction at the farthest injection well (30 km), from 103 cells/mL to 101 cells/mL, after 3 months treatment. Field trial A1 – After applying glutaraldehyde/THNM to production and injection water, SRB/APB levels were reduced (~108 CFU/mL to 102 CFU/mL) at the farthest injection well (7 km) after 1 month treatment. Field trial A2 – Following the treatment of production and injection water, all monitored points demonstrated a reduction of SRB counts from ~107 CFU/mL to 102-103 CFU/mL after 6 weeks. Furthermore, in the B1 and A1 trials, NGS results indicated a shift of the microbial population to less harmful (non-MIC relevant) organisms. Overall, the novelt
{"title":"Evaluation of a Glutaraldehyde/THNM Combination for Microbial Control in Four Conventional Oilfields","authors":"M. Paschoalino, Jon B Raymond, E. Sianawati, Veronica Silva","doi":"10.2118/193594-MS","DOIUrl":"https://doi.org/10.2118/193594-MS","url":null,"abstract":"\u0000 The performance of a new synergistic biocide combination based on glutaraldehyde and THNM (tris (hydroxymethyl) nitromethane) was extensively evaluated in laboratory trials using water samples from twenty-six Brazilian and Argentinian oilfields. The performance was ultimately validated in four field trials, two per country (A1, A2, B1, B2), over a three month duration.\u0000 For laboratory tests, water samples were collected from numerous locations of the various oilfields and characterized/enumerated by serial dilution (SRB and APB bug bottles), ATP, and molecular biology techniques (NGS). Water and isolated indigenous SRB/APB from the most contaminated locations were used as the matrix and test inoculum for the biocide optimization tests. Numerous biocide systems, at total active ingredient concentrations ranging from 111 to 250 ppm, were evaluated by assessing the ability to rapidly kill the native organisms (2 hour contact time at room temperature) and protect the water from contamination over a prolonged time frame (≥7 days) under heat-aged conditions (60°C). Results demonstrated that glutaraldehyde/THNM provided the best performance in the majority of the samples evaluated and was therefore selected for performance evaluations in field tests owing to the enhanced performance of this particular treatment in the laboratory.\u0000 Field trials were conducted by applying the lowest total biocide concentration that demonstrated a ≥ 4 log10 microbial reduction (in the laboratory studies) at various problematic field locations. All biocides were dosed as batch treatments 2-3 times per week (2-3 hours per treatment). Specifically, the co-dosed glutaraldehyde/THNM combination replaced incumbent treatments of either THPS or glutaraldehyde (batch dosed) in combination with a quaternary ammonium compound which was being applied by continuous injection:\u0000 Field trial B1 – Results showed a significant reduction in bacterial counts at the farthest injection well (12 km from the point of biocide application). Total anaerobic bacteria levels were reduced from ~106 CFU/mL to less than 102 CFU/mL after 1 month treatment. Additionally, total biocide consumption was reduced by 24% as compared to the incumbent biocides traditionally applied. Field trial B2 – Following treatment of injection water, SRB results showed a reduction at the farthest injection well (30 km), from 103 cells/mL to 101 cells/mL, after 3 months treatment. Field trial A1 – After applying glutaraldehyde/THNM to production and injection water, SRB/APB levels were reduced (~108 CFU/mL to 102 CFU/mL) at the farthest injection well (7 km) after 1 month treatment. Field trial A2 – Following the treatment of production and injection water, all monitored points demonstrated a reduction of SRB counts from ~107 CFU/mL to 102-103 CFU/mL after 6 weeks.\u0000 Furthermore, in the B1 and A1 trials, NGS results indicated a shift of the microbial population to less harmful (non-MIC relevant) organisms. Overall, the novelt","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89346776","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. Azuddin, I. Davis, Michael A. Singleton, S. Geiger, E. Mackay, Duarte Silva
When CO2 is injected into an aquifer, the injected CO2 is generally colder than the reservoir rock; this results in thermal gradients along the flow path. The temperature variation has an impact on CO2 solubility and the kinetics of any mineral reactions. Core flood experiments and associated reactive transport simulations were conducted to analyse thermal effects during CO2 injection in a dolomitic limestone aquifer and to quantify how CO2 solubility and mineral reactivity are affected. The experiments were conducted by injecting acidified brine into an Edwards Limestone core sample. A back pressure of 400 psi and injection rates of 30 mL/hr and 300 mL/hr were used. A range of temperatures from 21 °C to 70 °C were examined. Changes in the outlet fluid composition and changes in porosity and permeability were analysed. A compositional simulation model was used to further analyse the experiments. The simulations were history-matched to the experimental data by changing the reactive surface area and the kinetic rate parameter. The calibrated model was then used to test the sensitivity to CO2 injection rate and temperature. The impact of temperature on CO2-induced mineral reactions was observed from changes in mineral volume, porosity and permeability. The reaction rate constants estimated from the outlet solution concentrations are much lower than existing data for individual minerals. The estimated specific surface areas for carbonate minerals are in reasonable agreement with published values. The numerical investigations showed that at the lower temperatures, despite the reaction rates being slower, the solubility of the minerals was higher, and so as a result of these competing effects, moderately elevated calcium and magnesium concentrations were observed in the effluent. At higher temperatures, the solubilities of the minerals were lower, but now the reactions rates were higher, so similar effluent concentrations could be achieved. However, at higher flow rates, characterized by a lower Damköhler number, the residence times were shorter, and so lower effluent concentrations were observed. Additionally, the solubilities of calcite and dolomite varied to different extents with temperature, and so the calcium to magnesium molar ratio in the effluent brine increased with increasing temperature. The change in mineral composition during CO2 injection varies between the near well zone and the deeper reservoir. Near the well where the temperatures will be lower, solubilities are elevated, but the kinetic reaction rates and residence times will be lower, somewhat limiting dissolution. Deeper in the aquifer the solubilities will be reduced and residence times will be longer, enabling an equilibrium to be established. Modelling is thus required to connect these flow regimes.
{"title":"Impact of Temperature on Fluid-Rock Interactions During CO2 Injection in Depleted Limestone Aquifers: Laboratory and Modelling Studies","authors":"F. Azuddin, I. Davis, Michael A. Singleton, S. Geiger, E. Mackay, Duarte Silva","doi":"10.2118/193562-MS","DOIUrl":"https://doi.org/10.2118/193562-MS","url":null,"abstract":"\u0000 When CO2 is injected into an aquifer, the injected CO2 is generally colder than the reservoir rock; this results in thermal gradients along the flow path. The temperature variation has an impact on CO2 solubility and the kinetics of any mineral reactions. Core flood experiments and associated reactive transport simulations were conducted to analyse thermal effects during CO2 injection in a dolomitic limestone aquifer and to quantify how CO2 solubility and mineral reactivity are affected.\u0000 The experiments were conducted by injecting acidified brine into an Edwards Limestone core sample. A back pressure of 400 psi and injection rates of 30 mL/hr and 300 mL/hr were used. A range of temperatures from 21 °C to 70 °C were examined. Changes in the outlet fluid composition and changes in porosity and permeability were analysed. A compositional simulation model was used to further analyse the experiments. The simulations were history-matched to the experimental data by changing the reactive surface area and the kinetic rate parameter. The calibrated model was then used to test the sensitivity to CO2 injection rate and temperature.\u0000 The impact of temperature on CO2-induced mineral reactions was observed from changes in mineral volume, porosity and permeability. The reaction rate constants estimated from the outlet solution concentrations are much lower than existing data for individual minerals. The estimated specific surface areas for carbonate minerals are in reasonable agreement with published values. The numerical investigations showed that at the lower temperatures, despite the reaction rates being slower, the solubility of the minerals was higher, and so as a result of these competing effects, moderately elevated calcium and magnesium concentrations were observed in the effluent. At higher temperatures, the solubilities of the minerals were lower, but now the reactions rates were higher, so similar effluent concentrations could be achieved. However, at higher flow rates, characterized by a lower Damköhler number, the residence times were shorter, and so lower effluent concentrations were observed. Additionally, the solubilities of calcite and dolomite varied to different extents with temperature, and so the calcium to magnesium molar ratio in the effluent brine increased with increasing temperature.\u0000 The change in mineral composition during CO2 injection varies between the near well zone and the deeper reservoir. Near the well where the temperatures will be lower, solubilities are elevated, but the kinetic reaction rates and residence times will be lower, somewhat limiting dissolution. Deeper in the aquifer the solubilities will be reduced and residence times will be longer, enabling an equilibrium to be established. Modelling is thus required to connect these flow regimes.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81166034","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 benefits of a nanoparticle-weighted fluid are numerous, allowing the possibility of high-density drilling fluids, a true alternative to expensive heavy brines, barite-weighted reservoir drill-in fluids and the virtual elimination of barite sag. By using a branched carboxylic acid, rather than a linear molecule as a crystal growth inhibitor during precipitation, true nano-scale dispersions have been achieved that are stable in water, with no detectable agglomeration and that are self-dispersing after drying. This paper proposes that greater steric hindrance and smaller particle sizes are achieved by utilising branched, or chair-like carboxylic acids, rather than the long-chain molecules more commonly used. The use of FTIR, XRD, DLS and SSNRM have been combined to demonstrate that inhibitor concentration is the dominant effect in preventing crystal growth but does not account for particle growth retardation alone. Spherical nanoparticles with a dispersed ZAvg of 16nm and low contact areas have been created. They produce dispersions with a density of 2.27g/cm3. These dispersions display no detectable ‘sag’ after 428 days in suspension suggesting that colloidal stabilisation has been achieved. This paper also demonstrates that further decreases in particle diameter are possible through a combination of mechanical shear during precipitation and pH modification after precipitation has ceased. An optimum pH post-precipitation of 10.4 is close to that targeted by many water-based reservoir drill-in fluids, further highlighting the possibility of surfactant-inhibited barium sulphate nanoparticles as a density agent for drilling fluids. Using pH to modify the PSD of the nanoparticle dispersions strongly suggests that the dispersions can be tuned to one suitable for the intended operation. The growth inhibitors used during precipitation are low-cost and non-toxic and enable the dry particles to disperse to comparable PSDs after drying to their precipitated values. The technology allows the creation of a high-density brine replacement fluid, presenting a significant cost saving over an alternative such as caesium formate in some applications Previous research on barium sulphate nanoparticles [3] succeeded via the adsorption of long-chain carboxylic acids. We have shown that shorter, branched carboxylic acids - a new approach - are more effective and in significantly lower concentrations. This paper has found that a rigid, chair-like molecule provides an equivalent particle size distribution at an ultra-low adsorption level.
{"title":"Surfactant-Inhibited Barium Sulphate Nanoparticles for Use in Drilling or Completion Fluids","authors":"J. Whyte","doi":"10.2118/193578-MS","DOIUrl":"https://doi.org/10.2118/193578-MS","url":null,"abstract":"\u0000 The benefits of a nanoparticle-weighted fluid are numerous, allowing the possibility of high-density drilling fluids, a true alternative to expensive heavy brines, barite-weighted reservoir drill-in fluids and the virtual elimination of barite sag. By using a branched carboxylic acid, rather than a linear molecule as a crystal growth inhibitor during precipitation, true nano-scale dispersions have been achieved that are stable in water, with no detectable agglomeration and that are self-dispersing after drying. This paper proposes that greater steric hindrance and smaller particle sizes are achieved by utilising branched, or chair-like carboxylic acids, rather than the long-chain molecules more commonly used. The use of FTIR, XRD, DLS and SSNRM have been combined to demonstrate that inhibitor concentration is the dominant effect in preventing crystal growth but does not account for particle growth retardation alone.\u0000 Spherical nanoparticles with a dispersed ZAvg of 16nm and low contact areas have been created. They produce dispersions with a density of 2.27g/cm3. These dispersions display no detectable ‘sag’ after 428 days in suspension suggesting that colloidal stabilisation has been achieved. This paper also demonstrates that further decreases in particle diameter are possible through a combination of mechanical shear during precipitation and pH modification after precipitation has ceased. An optimum pH post-precipitation of 10.4 is close to that targeted by many water-based reservoir drill-in fluids, further highlighting the possibility of surfactant-inhibited barium sulphate nanoparticles as a density agent for drilling fluids. Using pH to modify the PSD of the nanoparticle dispersions strongly suggests that the dispersions can be tuned to one suitable for the intended operation. The growth inhibitors used during precipitation are low-cost and non-toxic and enable the dry particles to disperse to comparable PSDs after drying to their precipitated values. The technology allows the creation of a high-density brine replacement fluid, presenting a significant cost saving over an alternative such as caesium formate in some applications\u0000 Previous research on barium sulphate nanoparticles [3] succeeded via the adsorption of long-chain carboxylic acids. We have shown that shorter, branched carboxylic acids - a new approach - are more effective and in significantly lower concentrations. This paper has found that a rigid, chair-like molecule provides an equivalent particle size distribution at an ultra-low adsorption level.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83955113","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}
Although iron sulphide (FeS) scale is not as common as carbonate and sulfate scales, it is difficult to inhibit, especially at high temperature conditions, due to its low solubility and fast precipitation kinetics. Moreover, the complexity of FeS solution and solid phase chemistry makes FeS deposition and related issues difficult to be solved. This study is to identify more efficient and effective dispersants and inhibitors for FeS scale. Polyacrylamide (PAM), polyvinyl pyrrolidone (PVP), polyoxazoline (OX) and carboxymethyl cellulose (CMC), which are frequently employed during oil and gas production activities for various purposes, successfully prevented FeS particles from settling. CMC was the most effective to disperse FeS particles in brines and it can disperse FeS particles under the conditions of as high as 4M of ionic strength. The size of FeS stabilized with polymers remained in nano-scale. Polymers did not work as threshold inhibitors, but prevented particle growth. Phosphonates and carboxylate chelating agents were also tested for FeS scale inhibition. Diethylenetriamine pentamethylene phosphonate (DTPMP), ethylenediaminetetraacetate (EDTA) and nitrilotriacetate (NTA) successfully inhibited FeS nucleation greater than 90% in a given reaction time of 2 hours at 70 °C, based on the measurement of Fe concentration in filtered solution with 0.22 μm syringe membrane. NTA showed the best inhibition performance at pH 5.0 and all three inhibitors stopped FeS nucleation at a substoichiometric concentration of inhibitors to iron(II). EDTA performed better than NTA and DTPMP at pH 6.7 at about 10% excess of EDTA molar concentration over iron(II). As pH and saturation index (SI) increased, greater concentrations of inhibitors were required to inhibit FeS scale.
{"title":"Identification of Novel Chemicals for Iron Sulfide Scale Control and Understanding of Scale Controlling Mechanism","authors":"Saebom Ko, Xin Wang, A. Kan, M. Tomson","doi":"10.2118/193550-MS","DOIUrl":"https://doi.org/10.2118/193550-MS","url":null,"abstract":"\u0000 Although iron sulphide (FeS) scale is not as common as carbonate and sulfate scales, it is difficult to inhibit, especially at high temperature conditions, due to its low solubility and fast precipitation kinetics. Moreover, the complexity of FeS solution and solid phase chemistry makes FeS deposition and related issues difficult to be solved. This study is to identify more efficient and effective dispersants and inhibitors for FeS scale. Polyacrylamide (PAM), polyvinyl pyrrolidone (PVP), polyoxazoline (OX) and carboxymethyl cellulose (CMC), which are frequently employed during oil and gas production activities for various purposes, successfully prevented FeS particles from settling. CMC was the most effective to disperse FeS particles in brines and it can disperse FeS particles under the conditions of as high as 4M of ionic strength. The size of FeS stabilized with polymers remained in nano-scale. Polymers did not work as threshold inhibitors, but prevented particle growth. Phosphonates and carboxylate chelating agents were also tested for FeS scale inhibition. Diethylenetriamine pentamethylene phosphonate (DTPMP), ethylenediaminetetraacetate (EDTA) and nitrilotriacetate (NTA) successfully inhibited FeS nucleation greater than 90% in a given reaction time of 2 hours at 70 °C, based on the measurement of Fe concentration in filtered solution with 0.22 μm syringe membrane. NTA showed the best inhibition performance at pH 5.0 and all three inhibitors stopped FeS nucleation at a substoichiometric concentration of inhibitors to iron(II). EDTA performed better than NTA and DTPMP at pH 6.7 at about 10% excess of EDTA molar concentration over iron(II). As pH and saturation index (SI) increased, greater concentrations of inhibitors were required to inhibit FeS scale.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86318947","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation. This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C. This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions. The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator. A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible in situ geochemical reactions (precipitation, dissolution, ion exchange) and account for observed ion trends. The model predicts that the process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. It has been observed previously that high temperature (130°C) chalk reservoirs may act as natural sulphate reduction plants during seawater flooding, reducing sulphate scaling and souring risks, and so reducing the operating costs (scale squeeze treatment frequency, chemical volumes) of these fields. This work illustrates new evidence of magnesium depletion and sulphate retardation above levels expected for just brine/brine interactions for a 130° C sandstone reservoir with the implication that the geochemical reactions may lead to reduced operating costs (in terms of squeeze treatment volumes and treatment frequencies) in sandstone reservoirs with low carbonate mineral content that are undergoing seawater flooding.
{"title":"Magnesium Depletion and Impact on Produced Brine Compositions in a Waterflooded Reservoir","authors":"Oleg Ishkov, E. Mackay, M. Jordan, S. Blair","doi":"10.2118/193638-MS","DOIUrl":"https://doi.org/10.2118/193638-MS","url":null,"abstract":"\u0000 Produced water composition analysis provides evidence of what geochemical reactions are taking place in the reservoir. This information can be useful for predicting and managing oilfield mineral scale resulting from brine supersaturation.\u0000 This paper presents results of a study of the produced brine compositions from three wells in a field operated in the North Sea, with geochemical modelling complementing the analysis. The findings presented in this work provide evidence of magnesium depletion and sulphate retardation in a sandstone reservoir at 130° C.\u0000 This adjusted formation water composition was then used for calculations of the injection water fraction in each of the produced water samples. The Reacting Ions Toolkit was used to plot data in a variety of formats, including ion concentration vs. ion concentration, ion concentration vs. injection water fraction and ion concentration vs. time to identify trends and to examine the extent of involvement of the various ions in geochemical reactions.\u0000 The breakthrough of sulphate, a component primarily introduced during seawater flooding, was retarded during injection water breakthrough. Observed sulphate concentrations were lower than predicted for the case of brine/brine interactions only. The implication of this sulphate reduction was lower minimum inhibitor concentration required to control scale formation and longer squeeze treatment lifetimes for the operator.\u0000 A brine/rock interaction mechanism was proposed that involves magnesium depletion and is reproduced in the reactive transport model. 1D reactive transport modelling was performed to match possible in situ geochemical reactions (precipitation, dissolution, ion exchange) and account for observed ion trends. The model predicts that the process, which is beneficial in terms of reducing the scale risk, is more pronounced at higher temperatures. It has been observed previously that high temperature (130°C) chalk reservoirs may act as natural sulphate reduction plants during seawater flooding, reducing sulphate scaling and souring risks, and so reducing the operating costs (scale squeeze treatment frequency, chemical volumes) of these fields. This work illustrates new evidence of magnesium depletion and sulphate retardation above levels expected for just brine/brine interactions for a 130° C sandstone reservoir with the implication that the geochemical reactions may lead to reduced operating costs (in terms of squeeze treatment volumes and treatment frequencies) in sandstone reservoirs with low carbonate mineral content that are undergoing seawater flooding.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81396244","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}
Christopher S. Daeffler, Dominic V. Perroni, S. Makarychev-Mikhailov, A. Mirakyan
Viscoelastic surfactants (VES) are important gelling agents in well stimulation treatments. Proper job design requires that the additives create the desired viscosity for effective proppant or gravel pack sand transport. Post-stimulation production enhancement partially relies on the thoroughness of gelling agent destruction or removal, known as "breaking" the gel. VES gels are non-damaging and do not create a filter cake, and thus are prone to high leak-off. The leak-off fluid potentially has a high zero-shear viscosity and can be challenging to remove from the formation. We propose a breaker system that comprises a monomer and radical initiator that will travel into to the formation with the VES gel. The resulting polymer will disrupt the worm-like micelles of the VES, creating spherical micelles and reducing the viscosity of the fluid. The breaker system presented here is operable at 200 °F. Rheology measurements show that the VES fluid with monomer and initiator has reduced viscosity and becomes less shear-thinning. Optical transmission and backscattering measurements show that the presence of breaker does not greatly accelerate proppant settling. The reduced viscosity would not adversely affect proppant transport. Core flow experiments compared retained permeability of cores treated with VES and VES with reacted monomer and initiator. The core flushed with broken fluid possessed a retained permeability of 79%, while the unmodified VES left only 44% retained permeability.
{"title":"Internal Viscoelastic Surfactant Breakers from In-Situ Oligomerization","authors":"Christopher S. Daeffler, Dominic V. Perroni, S. Makarychev-Mikhailov, A. Mirakyan","doi":"10.2118/193563-MS","DOIUrl":"https://doi.org/10.2118/193563-MS","url":null,"abstract":"\u0000 Viscoelastic surfactants (VES) are important gelling agents in well stimulation treatments. Proper job design requires that the additives create the desired viscosity for effective proppant or gravel pack sand transport. Post-stimulation production enhancement partially relies on the thoroughness of gelling agent destruction or removal, known as \"breaking\" the gel. VES gels are non-damaging and do not create a filter cake, and thus are prone to high leak-off. The leak-off fluid potentially has a high zero-shear viscosity and can be challenging to remove from the formation. We propose a breaker system that comprises a monomer and radical initiator that will travel into to the formation with the VES gel. The resulting polymer will disrupt the worm-like micelles of the VES, creating spherical micelles and reducing the viscosity of the fluid. The breaker system presented here is operable at 200 °F. Rheology measurements show that the VES fluid with monomer and initiator has reduced viscosity and becomes less shear-thinning. Optical transmission and backscattering measurements show that the presence of breaker does not greatly accelerate proppant settling. The reduced viscosity would not adversely affect proppant transport. Core flow experiments compared retained permeability of cores treated with VES and VES with reacted monomer and initiator. The core flushed with broken fluid possessed a retained permeability of 79%, while the unmodified VES left only 44% retained permeability.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88336614","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}
Wai Li, Jishan Liu, Xionghu Zhao, Ji-wei Jiang, Hui Peng, Min Zhang, Tao He, Guannan Liu, Peiyuan Shen
Biodiesel-based drilling fluid (BBDF) draws considerable attention because biodiesel has excellent environmental acceptability and great potential to provide high drilling performance. There are some investigations reported about BBDF both in laboratory and in the field recently, demonstrating its feasibility. In contrast to traditional petrodiesel and mineral oil, biodiesel has some chemical activity which affects the reliability of BBDF in drilling environment. This paper details the principles and strategies for developing and selecting additives of BBDF. A variety of experimental results obtained by laboratory tests were presented to elucidate the importance of suitable additives for an eligible BBDF. Electrical stability test and centrifuge test were conducted to evaluate the effectiveness of emulsifier. A six-speed viscometer and a high-pressure-high-temperature (HPHT) rheometer were used to measure the parameters of BBDF to evaluate organophilic clays and rheological modifiers. Density test was performed to investigate the suspendability of the fluids. Hot rolling treatment was carried out to study the thermal tolerance of the fluids. The laboratory results and the literature showed that both lime content and calcium chloride concentration have significant effects on the stability and rheological parameters of BBDF. Even moderate amount of lime in BBDF will significantly decrease the stability of BBDF. The effect of calcium chloride concentration on BBDF varies according to the type of emulsifier. A compound emulsifier based on fatty alkanolamides and alkyl sulfonates exhibits reliable ability to prepare stable, thermal-tolerate invert biodiesel emulsion. It offers biodiesel emulsion reduced viscosity compared to those given by traditional Span/Tween emulsifier combinations. For another, commercial organophilic clays cannot give satisfactory rheological parameters because the viscosity-temperature profile of BBDF is often steeper than those of traditional oil based drilling fluids (OBDFs). Therefore, rheological modifier should be used to compensate the viscosity loss of BBDF under high-temperature conditions. A condensate of alkoxylated fatty amine and polycarboxylic acid showed good performance to provide a relatively flat rheological profile. Some empirical laws, principles and strategies are summarized for BBDF additive selection. One is that the combinations of non-ionic and anionic emulsifiers have better effectiveness for biodiesel. The other conclusion is that lime content must be strictly controlled. With the boom of the biodiesel industry, it is predicted BBDF will take a place in the family of drilling fluid. However, most previous works show that BBDF may be not satisfactory when the temperature is over 120 Celsius degrees. This work presents valuable experience for further improvement of this promising drilling fluid.
{"title":"Development and Screening of Additives for Biodiesel Based Drilling Fluids: Principles, Strategies and Experience","authors":"Wai Li, Jishan Liu, Xionghu Zhao, Ji-wei Jiang, Hui Peng, Min Zhang, Tao He, Guannan Liu, Peiyuan Shen","doi":"10.2118/193597-MS","DOIUrl":"https://doi.org/10.2118/193597-MS","url":null,"abstract":"\u0000 Biodiesel-based drilling fluid (BBDF) draws considerable attention because biodiesel has excellent environmental acceptability and great potential to provide high drilling performance. There are some investigations reported about BBDF both in laboratory and in the field recently, demonstrating its feasibility. In contrast to traditional petrodiesel and mineral oil, biodiesel has some chemical activity which affects the reliability of BBDF in drilling environment. This paper details the principles and strategies for developing and selecting additives of BBDF. A variety of experimental results obtained by laboratory tests were presented to elucidate the importance of suitable additives for an eligible BBDF. Electrical stability test and centrifuge test were conducted to evaluate the effectiveness of emulsifier. A six-speed viscometer and a high-pressure-high-temperature (HPHT) rheometer were used to measure the parameters of BBDF to evaluate organophilic clays and rheological modifiers. Density test was performed to investigate the suspendability of the fluids. Hot rolling treatment was carried out to study the thermal tolerance of the fluids. The laboratory results and the literature showed that both lime content and calcium chloride concentration have significant effects on the stability and rheological parameters of BBDF. Even moderate amount of lime in BBDF will significantly decrease the stability of BBDF. The effect of calcium chloride concentration on BBDF varies according to the type of emulsifier. A compound emulsifier based on fatty alkanolamides and alkyl sulfonates exhibits reliable ability to prepare stable, thermal-tolerate invert biodiesel emulsion. It offers biodiesel emulsion reduced viscosity compared to those given by traditional Span/Tween emulsifier combinations. For another, commercial organophilic clays cannot give satisfactory rheological parameters because the viscosity-temperature profile of BBDF is often steeper than those of traditional oil based drilling fluids (OBDFs). Therefore, rheological modifier should be used to compensate the viscosity loss of BBDF under high-temperature conditions. A condensate of alkoxylated fatty amine and polycarboxylic acid showed good performance to provide a relatively flat rheological profile. Some empirical laws, principles and strategies are summarized for BBDF additive selection. One is that the combinations of non-ionic and anionic emulsifiers have better effectiveness for biodiesel. The other conclusion is that lime content must be strictly controlled. With the boom of the biodiesel industry, it is predicted BBDF will take a place in the family of drilling fluid. However, most previous works show that BBDF may be not satisfactory when the temperature is over 120 Celsius degrees. This work presents valuable experience for further improvement of this promising drilling fluid.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85448573","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 practice of squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention, adsorption/desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor onto the mineral surface of the reservoir. Previously published studies have shown that the retention of phosphonate scale inhibitors in sandstone reservoirs can be enhanced through the addition of a ‘squeeze life enhancer’. This chemical, typically, a highly charged, low molecular weight polymer can be applied in either the preflush or overflush stage of the scale squeeze treatment. To date these studies have been conducted using low temperature (85°C) sandpack testing. This paper details the laboratory work carried out under high temperature (146°C) field conditions to qualify the use of the squeeze life enhancer for field application. The results of the formation damage/inhibitor return corefloods using an MEA phosphonate (EABMPA, Ethanolaminebis(Methylene Phosphonic Acid)) and polymeric squeeze life enhancer additive are presented. The coreflood results indicated that the addition of the additive within the overflush stage of the squeeze program resulted in a 19% extension of the inhibitor lifetime. The ability to extend the squeeze treatment was translated into reduced injected squeeze fluid treatment volume as injected fluid volumes was an issue for the wells being treated and therefore reduced associated oil deferment costs. The paper will also present field data obtained from the initial two field trial treatments which were carried out in a North Sea field. The trial well had been treated more than ten times previously with the same MEA phosphonate as applied in the enhancer trial making direct comparison of the treatment performance possible. The treatment program applied to the wells resulted in no change to the clean-up rates of the treated well and no process upset during well reflow. The initial scale inhibitor returns from the field trial treatments showed the expected improvement suggested from the coreflood study. The study brings value to the industry by providing the process to follow for qualifying and trialling a new technology in a challenging high temperature scaling environment with the results from the field supporting the carefully designed chemical selection and evaluation program.
{"title":"Enhancing Scale Inhibitor Squeeze Retention in HT/HP & High Water Rate Wells - Laboratory to Field Case Study","authors":"L. Sutherland, M. Jordan","doi":"10.2118/193600-MS","DOIUrl":"https://doi.org/10.2118/193600-MS","url":null,"abstract":"\u0000 The practice of squeeze treatments to oil/gas production wells to prevent inorganic scale formation has been applied for over 30 years and during that period different mechanisms to retain the inhibitor chemical have been evaluated. The simple mechanism of inhibitor retention, adsorption/desorption has been complemented over the years by enhanced adsorption via mutual solvent and full precipitation of the active inhibitor onto the mineral surface of the reservoir.\u0000 Previously published studies have shown that the retention of phosphonate scale inhibitors in sandstone reservoirs can be enhanced through the addition of a ‘squeeze life enhancer’. This chemical, typically, a highly charged, low molecular weight polymer can be applied in either the preflush or overflush stage of the scale squeeze treatment. To date these studies have been conducted using low temperature (85°C) sandpack testing.\u0000 This paper details the laboratory work carried out under high temperature (146°C) field conditions to qualify the use of the squeeze life enhancer for field application.\u0000 The results of the formation damage/inhibitor return corefloods using an MEA phosphonate (EABMPA, Ethanolaminebis(Methylene Phosphonic Acid)) and polymeric squeeze life enhancer additive are presented. The coreflood results indicated that the addition of the additive within the overflush stage of the squeeze program resulted in a 19% extension of the inhibitor lifetime. The ability to extend the squeeze treatment was translated into reduced injected squeeze fluid treatment volume as injected fluid volumes was an issue for the wells being treated and therefore reduced associated oil deferment costs.\u0000 The paper will also present field data obtained from the initial two field trial treatments which were carried out in a North Sea field. The trial well had been treated more than ten times previously with the same MEA phosphonate as applied in the enhancer trial making direct comparison of the treatment performance possible. The treatment program applied to the wells resulted in no change to the clean-up rates of the treated well and no process upset during well reflow. The initial scale inhibitor returns from the field trial treatments showed the expected improvement suggested from the coreflood study.\u0000 The study brings value to the industry by providing the process to follow for qualifying and trialling a new technology in a challenging high temperature scaling environment with the results from the field supporting the carefully designed chemical selection and evaluation program.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79026739","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
K. Raney, K. Alibek, Martin Shumway, Karthik N. Karathur, Terry Stanislav, Gary West, Marc Jacobs
New biochemically-derived products for the removal of paraffin wax from oil wells do not require additional capex nor heat and do not utilize bacteria. They contain inactivated microbial cells, biosurfactants and biosolvents, and other components harvested as microbial byproducts that emulsify and dissolve paraffin from rock pores and from the well surfaces over wide temperature, salinity, depth, and pH ranges. Additionally, they increase oil recovery by remediating near-wellbore formation damage, reducing interfacial tension, altering rock surfaces and changing their wettability, and reducing oil viscosity. The product application is environmentally superior to well treatments using hot oil/water and aromatic solvents and is economical due to low capital and operating costs required for product synthesis. Specifically, product preparation is achieved using a modular fermentation system that is installed near the points of application. This insures highly efficient and low-cost production and logistics, as well as reducing time from generation to application which maximizes potency. With sufficient space, water, and electricity, the initial manufacture of the dispersal products can occur within a few weeks. The treatment products utilized were initially developed and tested in laboratory studies, which showed that dispersion rates of the relevant paraffin samples were comparable to those achieved with toluene. The paraffin dispersal products exhibit a very high level of efficacy and safety when deployed in the Appalachian and Permian Basins. The potency of these products has led to outstanding paraffin removal results as indicated by reduced well failures in both vertical and horizontal wells and by visual observation of sucker rods removed from the wells. In addition, tank sludge and wax deposits in pipelines can be removed through either residual product flowing from the well or through direct application. Growth of detrimental bacteria and formation of biofilms are inhibited by the product application thereby reducing corrosion risk. Specifically, details of an almost two-year 70-well study in the Appalachian Basin are reported in which no well failures were observed due to paraffin buildup and 95% of the wells exhibited an enhanced oil recovery effect during the paraffin remediation treatments. This resulted in an approximate 50% average increase in sustained production rate over baseline. Analysis of the results forecasts a substantial increase in future production, thereby significantly enhancing the value of the producing wells. Importantly, longer times between required treatments and the increased recovery rates have transformed the paraffin maintenance program into a documented revenue generator for the operator.
{"title":"A Novel Biochemical-Based Paraffin Wax Removal Program Providing Revenue Generation and Asset Enhancement","authors":"K. Raney, K. Alibek, Martin Shumway, Karthik N. Karathur, Terry Stanislav, Gary West, Marc Jacobs","doi":"10.2118/193579-MS","DOIUrl":"https://doi.org/10.2118/193579-MS","url":null,"abstract":"\u0000 New biochemically-derived products for the removal of paraffin wax from oil wells do not require additional capex nor heat and do not utilize bacteria. They contain inactivated microbial cells, biosurfactants and biosolvents, and other components harvested as microbial byproducts that emulsify and dissolve paraffin from rock pores and from the well surfaces over wide temperature, salinity, depth, and pH ranges. Additionally, they increase oil recovery by remediating near-wellbore formation damage, reducing interfacial tension, altering rock surfaces and changing their wettability, and reducing oil viscosity. The product application is environmentally superior to well treatments using hot oil/water and aromatic solvents and is economical due to low capital and operating costs required for product synthesis. Specifically, product preparation is achieved using a modular fermentation system that is installed near the points of application. This insures highly efficient and low-cost production and logistics, as well as reducing time from generation to application which maximizes potency. With sufficient space, water, and electricity, the initial manufacture of the dispersal products can occur within a few weeks.\u0000 The treatment products utilized were initially developed and tested in laboratory studies, which showed that dispersion rates of the relevant paraffin samples were comparable to those achieved with toluene. The paraffin dispersal products exhibit a very high level of efficacy and safety when deployed in the Appalachian and Permian Basins. The potency of these products has led to outstanding paraffin removal results as indicated by reduced well failures in both vertical and horizontal wells and by visual observation of sucker rods removed from the wells. In addition, tank sludge and wax deposits in pipelines can be removed through either residual product flowing from the well or through direct application. Growth of detrimental bacteria and formation of biofilms are inhibited by the product application thereby reducing corrosion risk.\u0000 Specifically, details of an almost two-year 70-well study in the Appalachian Basin are reported in which no well failures were observed due to paraffin buildup and 95% of the wells exhibited an enhanced oil recovery effect during the paraffin remediation treatments. This resulted in an approximate 50% average increase in sustained production rate over baseline. Analysis of the results forecasts a substantial increase in future production, thereby significantly enhancing the value of the producing wells. Importantly, longer times between required treatments and the increased recovery rates have transformed the paraffin maintenance program into a documented revenue generator for the operator.","PeriodicalId":10983,"journal":{"name":"Day 1 Mon, April 08, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-03-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77881650","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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