Approach • Conduct baseline testing of the forward WGS (fWGS) reaction at high pressure with no c... more Approach • Conduct baseline testing of the forward WGS (fWGS) reaction at high pressure with no catalyst in the 300900°C range in the prototype Pd and Pd-Cu membrane reactors. • Re-design the membrane reactor to maximize membrane area and minimize thickness in order to enhance conversions of CO and H2O to H2 and CO2. • Determine H2 permeance of Pd-Cu in the presence of major gasifier components, such as CO, H2O, CO2.
The microsortation of clean, dry, mixed, shredded, post-consumer polyolefins can be accomplished ... more The microsortation of clean, dry, mixed, shredded, post-consumer polyolefins can be accomplished using near-critical carbon dioxide as a float-sink medium. At high loadings of plastics, however, buoyant forces alone are not sufficient to break up the aggregates of interlocking shredded plastic particles. Therefore a close-clearance impeller must be used to agitate the mixed plastics during the batch separation. This slight agitation permits these irregularly shaped chips to either float or sink without being hindered by surrounding chips. The separation apparatus operates most efficiently when the plastics are charged to a level that corresponds to the top of the highest blade of a large-diameter multiple-pitched blade impeller that rotates at 15 rpm. A post-consumer flake mixture of 85%HDPE/15%PP can be sorted into HDPE and PP streams of 99+% purity at loadings up to 56 volume%. In the absence of an impeller, high purity separations can be achieved at loadings of only 2 volume%. This dramatic increase in the loading reduces the estimated processing cost of mixed polyolefins to $0.03-0.05/lb, enhancing the economic feasibility of this high pressure, C02-based microsortation process. Immersion of these plastics in this high pressure environment during the separation resulted in insignificant changes in the plastics' properties
This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniq... more This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniques for unconventional liquid reservoirs (ULRs) can be increased through wettability alteration by adding a dilute non-ionic surfactant to CO2. The use of surfactants to increase the water-wetness of rock surfaces has previously been shown to improve oil recovery during water-based hydraulic fracturing and waterbased EOR in ULRs. In this study, nonionic surfactants are dissolved in CO2 to attain analogous significant shifts in wettability toward CO2-philic and oil-phobic. This could provide another EOR mechanism for the CO2-based recovery of oil from unconventional formations. The solubility of a nonionic, water-soluble, surfactant (Indorama SURFONIC® TDA-9, an ethoxylated alcohol with a branched tridecyl, oil-philic tail and nine ethylene oxide groups in the hydrophilic head group) in CO2 has been measured between 25 – 100 °C. This surfactant exhibits a solubility of roughly 1 wt% at pr...
Journal of Petroleum Science and Engineering, 2014
Abstract The addition of CO2-soluble, brine-soluble surfactants to the high pressure CO2 can faci... more Abstract The addition of CO2-soluble, brine-soluble surfactants to the high pressure CO2 can facilitate the in-situ generation of CO2-in-brine foams for conformance and/or mobility control. These non-ionic surfactants dissolve in CO2 to concentrations of roughly 0.02–0.10 wt% at typical CO2 enhanced oil recovery (EOR) conditions and, upon mixing with brine in a closed, agitated, windowed vessel, stabilize CO2-in-brine foams. Branched nonylphenol ethoxylates containing an average of 12 (Huntsman SURFONIC® N-120) or 15 (Huntsman SURFONIC® N-150) ethylene oxide (EO) repeat units, and a branched tridecyl alcohol ethoxylate with 9 EO repeat units (Huntsman SURFONIC® TDA-9) are selected for the mobility and computed tomography (CT) studies detailed in this paper. These foam-stabilizing surfactants are much more brine-soluble than CO2-soluble, in accordance with the Bancroft rule for generating CO2-in-brine foam. Transient mobility measurements are conducted using several mixed wettability SACROC carbonate cores of low permeability (13–16 mD), and a high permeability water-wet Bentheimer sandstone core (1550 mD). The CO2 is injected into a brine-saturated core at a constant rate, yielding superficial velocities of 60.96 cm/day or 304.8 cm/day. Surfactant was either not used, dissolved only in CO2, only in brine, or in both brine and CO2. The surfactant concentration is ~0.07 wt% in the CO2 (the maximum concentration capable of dissolving in CO2) or in the brine. The transient differential pressure drop during the injection of three pore volumes of CO2 into the core indicate that the average total pressure drop across the core during the experiment increases by an average of 25–120% when the surfactant is dissolved in the CO2, 79–300% when the surfactant is dissolved in the brine, and 220–330% if surfactant is present in both the brine and CO2. These results indicate that the greatest mobility reduction is achieved with the surfactant in both brine and CO2, and the foams that are generated with surfactant dissolved in the brine alone tend to provide greater mobility reduction than when the surfactant is dissolved only in CO2. CT scanning of in-situ foam generation is conducted by injecting high pressure CO2 into a 5 wt% KI brine-saturated water-wet Berea sandstone (4–8 mD). Tests are performed with no surfactant, surfactant dissolved in brine at 0.03 wt%, in CO2 at 0.07 wt%, or in both brine and CO2. CT images indicate that in the absence of surfactant, sweep efficiency is very low primarily because CO2 tends to flow through high permeability bedding planes. The use of CO2-soluble surfactants to form CO2-in-brine foam within a sandstone core is verified via CT imaging. At low and high superficial velocity values of 14.33–143.3 cm/day, in-situ foam generation and propagation, as indicated by piston-like flow of the CO2 through the core, is most evident when surfactant was dissolved in the brine. While there is some evidence of foam formation when Huntsman SURFONIC® N-120 or Huntsman SURFONIC® N-150 is present in the CO2, very distinct foam formation and propagation occurs when Huntsman SURFONIC® TDA-9 is dissolved in CO2.
Proceedings of SPE Symposium on Reservoir Simulation, 1991
ABSTRACT A black-oil, pseudo-miscible simulator, a compositional simulator, and a compositional/ ... more ABSTRACT A black-oil, pseudo-miscible simulator, a compositional simulator, and a compositional/ incomplete mixing simulator were used to model first-contact miscible!, carbon dioxide, enhanced-oil recovery experiments. The experiments were conducted by the University of Wyoming in a three-dimensional, high-pressure, physical model to investigate the effect of injection well geometry on oil recovery. These laboratory scale experiments showed that oil recovery could be significantly increased using a horizontal injection well instead of a vertical injection well. The objectives of this study were to evaluate the capability of each simulator to accurately model these displacements and to use the most appropriate simulator to investigate the mechanisms that led to improved oil recovery. Both the black-oil, pseudo-miscible simulator and the compositional simulator were unable to provide a match of the experimental results. The pseudo-miscible simulator overpredicted the recovery rate and the ultimate recovery of oil because it could not accurately account for the large volume change when mixing carbon dioxide and heptane (laboratory oil). Only limited success in providing better matches was attained when the effects of viscous fingering were incorporated by lowering the value of the mixing parameter. The overproduction of oil resulting from the poor phase behavior description was too large to be compensated for by altering the mixing parameter. The compositional simulator provided a more realistic description of the phase behavior and, therefore, yielded good matches of oil production before breakthrough. However, the recovery of oil after breakthrough was overpredicted. It was not possible to improve these simulation results by accounting for viscous-fingering effects since the compositional simulator assumes complete mixing in all grid blocks. A compositional/incomplete mixing simulator that empirically accounted for the macroscopic effects of viscous fingering by assuming incomplete mixing within grid blocks was then employed. An additional parameter was required to define the rate of mass transfer of oil from the ‘bypassed’ phase of a gridblock into the oil phase where mixing with the carbon dioxide was allowed to occur. A high value of the parameter (100 or more) corresponded to no viscous fingering as commonly assumed in conventional simulators, while a low value corresponded to the maximum degree of fingering effects. Good matches between simulation and experimental results for both the vertical and horizontal injection schemes were obtained using this model with parameter values of 0.1 and 2.5, respectively. These results indicated that viscous fingering probably occurred in all experiments, with the effect being much less pronounced when the horizontal injector was used.
A petroleum sulfonate (Petrostep 465/420) was combined with commercially available ethoxylated an... more A petroleum sulfonate (Petrostep 465/420) was combined with commercially available ethoxylated and other cosurfactants. Salt tolerance, phase volume behavior, interfacial tensions, and viscosities were measured; correlations among these parameters are presented for the 21 systems studied. Salinity tolerance levels as high as 120 g/kg NaCl, optimal salinities as high as 95 g/kg NaCl, and ultralow interfacial tensions on the order of 1 × 10-4 mN/m were exhibited by some systems. Optimal salinities were accompanied by ultralow interfacial tensions and lower microemulsion viscosities only when the range of salinity over which the three-phase region persisted was narrow. Furthermore, some systems were characterized by almost 95% microemulsion volume at optimal salinity. The width of the three-phase region decreased as the middle-phase microemulsion volume at optimal salinity increased. Consequently, the microemulsion viscosities were lower for systems that displayed a narrower three-phas...
The effect of the presence of an aqueous phase on the phase behavior of the CO/sub 2//tetradecane... more The effect of the presence of an aqueous phase on the phase behavior of the CO/sub 2//tetradecane and the CO/sub 2//Maljamar-crude-oil systems has been experimentally determined. Both the salinity and the amount of the aqueous phase were varied to test several methods of modeling. In the first technique, the amount of CO/sub 2/ ''lost'' to the aqueous phase was determined using Henry's law, decreasing the overall ratio of CO/sub 2/ to hydrocarbons, while the Peng-Robinson equation of state (PR EOS) was used to determine the phase distribution of the hydrocarbon phases. In the second technique, the equation of state (EOS) was modified to predict the densities and compositions of not only the hydrocarbon phases, but also the aqueous phase. Simply accounting for CO/sub 2/ solubility by incorporating Henry's law, used in conjunction with the Poynting correction and an empirical factor for salinity, not only gave results nearly identical with the EOS approach, but also required less computational effort. Both methods gave good agreement with the experimental data.
Approach • Conduct baseline testing of the forward WGS (fWGS) reaction at high pressure with no c... more Approach • Conduct baseline testing of the forward WGS (fWGS) reaction at high pressure with no catalyst in the 300900°C range in the prototype Pd and Pd-Cu membrane reactors. • Re-design the membrane reactor to maximize membrane area and minimize thickness in order to enhance conversions of CO and H2O to H2 and CO2. • Determine H2 permeance of Pd-Cu in the presence of major gasifier components, such as CO, H2O, CO2.
The microsortation of clean, dry, mixed, shredded, post-consumer polyolefins can be accomplished ... more The microsortation of clean, dry, mixed, shredded, post-consumer polyolefins can be accomplished using near-critical carbon dioxide as a float-sink medium. At high loadings of plastics, however, buoyant forces alone are not sufficient to break up the aggregates of interlocking shredded plastic particles. Therefore a close-clearance impeller must be used to agitate the mixed plastics during the batch separation. This slight agitation permits these irregularly shaped chips to either float or sink without being hindered by surrounding chips. The separation apparatus operates most efficiently when the plastics are charged to a level that corresponds to the top of the highest blade of a large-diameter multiple-pitched blade impeller that rotates at 15 rpm. A post-consumer flake mixture of 85%HDPE/15%PP can be sorted into HDPE and PP streams of 99+% purity at loadings up to 56 volume%. In the absence of an impeller, high purity separations can be achieved at loadings of only 2 volume%. This dramatic increase in the loading reduces the estimated processing cost of mixed polyolefins to $0.03-0.05/lb, enhancing the economic feasibility of this high pressure, C02-based microsortation process. Immersion of these plastics in this high pressure environment during the separation resulted in insignificant changes in the plastics' properties
This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniq... more This study attempts to determine if the efficacy of CO2-based enhanced oil recovery (EOR) techniques for unconventional liquid reservoirs (ULRs) can be increased through wettability alteration by adding a dilute non-ionic surfactant to CO2. The use of surfactants to increase the water-wetness of rock surfaces has previously been shown to improve oil recovery during water-based hydraulic fracturing and waterbased EOR in ULRs. In this study, nonionic surfactants are dissolved in CO2 to attain analogous significant shifts in wettability toward CO2-philic and oil-phobic. This could provide another EOR mechanism for the CO2-based recovery of oil from unconventional formations. The solubility of a nonionic, water-soluble, surfactant (Indorama SURFONIC® TDA-9, an ethoxylated alcohol with a branched tridecyl, oil-philic tail and nine ethylene oxide groups in the hydrophilic head group) in CO2 has been measured between 25 – 100 °C. This surfactant exhibits a solubility of roughly 1 wt% at pr...
Journal of Petroleum Science and Engineering, 2014
Abstract The addition of CO2-soluble, brine-soluble surfactants to the high pressure CO2 can faci... more Abstract The addition of CO2-soluble, brine-soluble surfactants to the high pressure CO2 can facilitate the in-situ generation of CO2-in-brine foams for conformance and/or mobility control. These non-ionic surfactants dissolve in CO2 to concentrations of roughly 0.02–0.10 wt% at typical CO2 enhanced oil recovery (EOR) conditions and, upon mixing with brine in a closed, agitated, windowed vessel, stabilize CO2-in-brine foams. Branched nonylphenol ethoxylates containing an average of 12 (Huntsman SURFONIC® N-120) or 15 (Huntsman SURFONIC® N-150) ethylene oxide (EO) repeat units, and a branched tridecyl alcohol ethoxylate with 9 EO repeat units (Huntsman SURFONIC® TDA-9) are selected for the mobility and computed tomography (CT) studies detailed in this paper. These foam-stabilizing surfactants are much more brine-soluble than CO2-soluble, in accordance with the Bancroft rule for generating CO2-in-brine foam. Transient mobility measurements are conducted using several mixed wettability SACROC carbonate cores of low permeability (13–16 mD), and a high permeability water-wet Bentheimer sandstone core (1550 mD). The CO2 is injected into a brine-saturated core at a constant rate, yielding superficial velocities of 60.96 cm/day or 304.8 cm/day. Surfactant was either not used, dissolved only in CO2, only in brine, or in both brine and CO2. The surfactant concentration is ~0.07 wt% in the CO2 (the maximum concentration capable of dissolving in CO2) or in the brine. The transient differential pressure drop during the injection of three pore volumes of CO2 into the core indicate that the average total pressure drop across the core during the experiment increases by an average of 25–120% when the surfactant is dissolved in the CO2, 79–300% when the surfactant is dissolved in the brine, and 220–330% if surfactant is present in both the brine and CO2. These results indicate that the greatest mobility reduction is achieved with the surfactant in both brine and CO2, and the foams that are generated with surfactant dissolved in the brine alone tend to provide greater mobility reduction than when the surfactant is dissolved only in CO2. CT scanning of in-situ foam generation is conducted by injecting high pressure CO2 into a 5 wt% KI brine-saturated water-wet Berea sandstone (4–8 mD). Tests are performed with no surfactant, surfactant dissolved in brine at 0.03 wt%, in CO2 at 0.07 wt%, or in both brine and CO2. CT images indicate that in the absence of surfactant, sweep efficiency is very low primarily because CO2 tends to flow through high permeability bedding planes. The use of CO2-soluble surfactants to form CO2-in-brine foam within a sandstone core is verified via CT imaging. At low and high superficial velocity values of 14.33–143.3 cm/day, in-situ foam generation and propagation, as indicated by piston-like flow of the CO2 through the core, is most evident when surfactant was dissolved in the brine. While there is some evidence of foam formation when Huntsman SURFONIC® N-120 or Huntsman SURFONIC® N-150 is present in the CO2, very distinct foam formation and propagation occurs when Huntsman SURFONIC® TDA-9 is dissolved in CO2.
Proceedings of SPE Symposium on Reservoir Simulation, 1991
ABSTRACT A black-oil, pseudo-miscible simulator, a compositional simulator, and a compositional/ ... more ABSTRACT A black-oil, pseudo-miscible simulator, a compositional simulator, and a compositional/ incomplete mixing simulator were used to model first-contact miscible!, carbon dioxide, enhanced-oil recovery experiments. The experiments were conducted by the University of Wyoming in a three-dimensional, high-pressure, physical model to investigate the effect of injection well geometry on oil recovery. These laboratory scale experiments showed that oil recovery could be significantly increased using a horizontal injection well instead of a vertical injection well. The objectives of this study were to evaluate the capability of each simulator to accurately model these displacements and to use the most appropriate simulator to investigate the mechanisms that led to improved oil recovery. Both the black-oil, pseudo-miscible simulator and the compositional simulator were unable to provide a match of the experimental results. The pseudo-miscible simulator overpredicted the recovery rate and the ultimate recovery of oil because it could not accurately account for the large volume change when mixing carbon dioxide and heptane (laboratory oil). Only limited success in providing better matches was attained when the effects of viscous fingering were incorporated by lowering the value of the mixing parameter. The overproduction of oil resulting from the poor phase behavior description was too large to be compensated for by altering the mixing parameter. The compositional simulator provided a more realistic description of the phase behavior and, therefore, yielded good matches of oil production before breakthrough. However, the recovery of oil after breakthrough was overpredicted. It was not possible to improve these simulation results by accounting for viscous-fingering effects since the compositional simulator assumes complete mixing in all grid blocks. A compositional/incomplete mixing simulator that empirically accounted for the macroscopic effects of viscous fingering by assuming incomplete mixing within grid blocks was then employed. An additional parameter was required to define the rate of mass transfer of oil from the ‘bypassed’ phase of a gridblock into the oil phase where mixing with the carbon dioxide was allowed to occur. A high value of the parameter (100 or more) corresponded to no viscous fingering as commonly assumed in conventional simulators, while a low value corresponded to the maximum degree of fingering effects. Good matches between simulation and experimental results for both the vertical and horizontal injection schemes were obtained using this model with parameter values of 0.1 and 2.5, respectively. These results indicated that viscous fingering probably occurred in all experiments, with the effect being much less pronounced when the horizontal injector was used.
A petroleum sulfonate (Petrostep 465/420) was combined with commercially available ethoxylated an... more A petroleum sulfonate (Petrostep 465/420) was combined with commercially available ethoxylated and other cosurfactants. Salt tolerance, phase volume behavior, interfacial tensions, and viscosities were measured; correlations among these parameters are presented for the 21 systems studied. Salinity tolerance levels as high as 120 g/kg NaCl, optimal salinities as high as 95 g/kg NaCl, and ultralow interfacial tensions on the order of 1 × 10-4 mN/m were exhibited by some systems. Optimal salinities were accompanied by ultralow interfacial tensions and lower microemulsion viscosities only when the range of salinity over which the three-phase region persisted was narrow. Furthermore, some systems were characterized by almost 95% microemulsion volume at optimal salinity. The width of the three-phase region decreased as the middle-phase microemulsion volume at optimal salinity increased. Consequently, the microemulsion viscosities were lower for systems that displayed a narrower three-phas...
The effect of the presence of an aqueous phase on the phase behavior of the CO/sub 2//tetradecane... more The effect of the presence of an aqueous phase on the phase behavior of the CO/sub 2//tetradecane and the CO/sub 2//Maljamar-crude-oil systems has been experimentally determined. Both the salinity and the amount of the aqueous phase were varied to test several methods of modeling. In the first technique, the amount of CO/sub 2/ ''lost'' to the aqueous phase was determined using Henry's law, decreasing the overall ratio of CO/sub 2/ to hydrocarbons, while the Peng-Robinson equation of state (PR EOS) was used to determine the phase distribution of the hydrocarbon phases. In the second technique, the equation of state (EOS) was modified to predict the densities and compositions of not only the hydrocarbon phases, but also the aqueous phase. Simply accounting for CO/sub 2/ solubility by incorporating Henry's law, used in conjunction with the Poynting correction and an empirical factor for salinity, not only gave results nearly identical with the EOS approach, but also required less computational effort. Both methods gave good agreement with the experimental data.
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Papers by Robert Enick