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Collaborating Authors
Huh, Chun
Summary Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced-oil-recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced-water management is also raised because residual HPAM in produced water could increase oil content and unwanted viscosity in discharging or reinjecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharge. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally friendly way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of an external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal with surface-modified MNPs and regeneration of spent MNPs for multiple reuse. MNPs, in-house synthesized with prescribed surface coating, were superparamagnetic with an average individual particle size of โ10โnm. The removal efficiency of HPAM from water with the MNPs depended on the type and concentration of brines, concentration of amine-functionalized MNPs, surface coating of MNPs, molecular weight of polymer, and how many times the MNPs were regenerated and reused. Virtually 100% removal of HPAM from water was feasible, depending on the reaction conditions. The regeneration of spent MNPs, with pH adjustment to recover the reactive sites, maintained more than 90% removal efficiency for three-time repetitive usages. The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chains; the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.
- North America > United States (0.46)
- Asia (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.51)
A Microfluidic Investigation of the Synergistic Effect of Nanoparticles and Surfactants in Macro-Emulsion-Based Enhanced Oil Recovery
Xu, Ke (University of Texas at Austin) | Zhu, Peixi (University of Texas at Austin) | Colon, Tatiana (Polytechnic University of Puerto Rico) | Huh, Chun (University of Texas at Austin) | Balhoff, Matthew (University of Texas at Austin)
Summary Injecting oil-in-water (O/W) emulsions stabilized with nanoparticles (NPs) or surfactants is a promising option for enhanced oil recovery (EOR) in harsh-condition reservoirs. Stability and rheology of the flowing emulsion in porous media are key factors for the effectiveness of the EOR method. The objective of this study is to use microfluidics to (1) quantitatively evaluate the synergistic effect of surfactants and NPs on emulsion dynamic stability and how NPs affect the emulsion properties, and to (2) investigate how emulsion properties affect the sweep performance in emulsion flooding. A microfluidic device with well-defined channel geometry of a high-permeability pathway and multiple parallel low-permeability pathways was created to represent a fracture/matrix dual-permeability system. Measurement of droplet coalescence frequency during flow is used to quantify the dynamic stability of emulsions. An NP aqueous suspension (2 wt%) shows excellent ability to stabilize the macro-emulsion when mixed with a trace amount of surfactant (0.05 wt%), revealing a synergistic effect between NPs and surfactant. For a stable emulsion, when a pore throat is present in the high-permeability pathway, it was observed that flowing emulsion droplets compress each other and then block the high-permeability pathway at a throat structure, which forces the wetting phase into low-permeability pathways. Droplet size shows little correlation with this blocking effect. Water content was observed to be much higher in the low-permeability pathways than in the high-permeability pathways, indicating different emulsion texture and viscosity in channels of different sizes. Consequently, the assumption of bulk emulsion viscosity in the porous medium is not applicable in the description and modeling of the emulsion-flooding process. Flow of emulsions stabilized by an NP/surfactant mixture shows droplet packing in high-permeability regions that is denser than those stabilized by surfactant only, at high-permeability regions, which is attributed to the enhanced interaction between droplets caused by NPs in the thin liquid film between neighboring oil/water (O/W) interfaces. This effect is shown to enhance the performance of emulsion-blockage effect for sweep-efficiency improvement, showing the advantage of NPs as an emulsion stabilizer during an emulsion-based EOR process.
- Asia (0.67)
- North America > United States (0.47)
- North America > Canada > Alberta (0.28)
Oil Droplet Removal from Produced Water Using Nanoparticles and Their Magnetic Separation
Ko, Saebom (University of Texas at Austin) | Kim, Eun Song (University of Texas at Austin) | Park, Siman (University of Texas at Austin) | Daigle, Hugh (University of Texas at Austin) | Milner, Thomas E. (University of Texas at Austin) | Huh, Chun (University of Texas at Austin) | Bennetzen, Martin V. (Maersk Oil) | Geremia, Giuliano A. (Maersk Oil Research and Technology Center)
Abstract The removal of highly stable dispersed oil produced during oil recovery processes is very challenging, especially in offshore operations where the limited space does not allow use of equipment with long residence time for the required separation. Using magnetic nanoparticles (MNPs) to remove the dispersed oil from produced water is a promising way to overcome the difficulties that the current treatment technologies face, since the MNPs-attached oil droplets can be quickly and efficiently separated with application of an external magnetic field. The MNPs can be also regenerated and reused, minimizing the generation of hazardous waste. We investigated not only the optimal operating conditions, such as MNP concentration and salinity, but also the mechanisms of MNPs-oil attachment and magnetic separation. We synthesized MNPs in the laboratory with a prescribed surface coating. The MNPs were superparamagnetic with an average individual particle size of ~10 nm. Crude oil content in separated water was reduced by as much as 99.9% using MNP concentrations as low as 0.04 wt% in 5 minutes after MNPs and oil were reacted. The electrostatic attraction between negatively charged oil-in-water emulsions and positively charged MNPs controls the attachment of MNPs to the droplet surface; and the subsequent aggregation of the electrically neutral MNPs-attached oil droplets plays a critical role for accelerated and efficient magnetic separation. The particle aggregation occurred fast, generally within one minute. Thus, the total magnetic separation time was dramatically reduced to as short as 1 second, contrary to that of free, individual MNPs where it took about 36~72 hours, depending on the MNP concentrations. Model calculations of magnetic separation velocity, accounting for the MNP magnetization and viscous drag, show that the velocity of free Amine functionalized MNPs (A-MNPs) increases about 1~3 orders of magnitude as the particles get closer to the magnet depending on the particle size. The smaller the particles, the greater the effect of the magnetic field on the velocity. A typical operating condition would be when the size of the MNPs-oil droplet aggregates is grown to be greater than 360 nm. Then, the total magnetic separation time will be approximately 5 minutes.
- North America > United States > Texas (0.46)
- Asia > Middle East > UAE (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.49)
The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells
Ho, Jostine Fei (The University of Texas at Austin) | Tavassoli, Shayan (The University of Texas at Austin) | Patterson, James W. (The University of Texas at Austin) | Shafiei, Mohammadreza (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Bommer, Paul M. (The University of Texas at Austin) | Bryant, Steven L. (The University of Texas at Austin) | Balhoff, Matthew T. (The University of Texas at Austin)
Summary The potential leakage of hydrocarbon fluids or carbon dioxide (CO2) out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil-and-gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10โ300โยตm can pose a significant leakage danger with effective permeability in the range of 0.1โ1.0 md. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair; thus, a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application with pH-triggered polymeric sealants could potentially be the solution to plugging these fractures. The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. The pH-sensitive microgels viscosify after neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition with real-time visual observation and measurements of pressure gradient and effluent pH. Although the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cations from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that were subjected to various degrees of syneresis often failed to hold backpressures. Multiple chemicals were tested for pretreatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer-gel strength is determined by recording the maximum-holdback pressure gradients during liquid-breakthrough tests after various periods of pretreatment and polymer shut-in time. Cores pretreated with Na5P3O10 successfully held up to an average of 70 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2-storage applications. The use of such inexpensive, pH-triggered polyacrylic acid polymer allows the sealing of leakage pathways effectively under high-pH conditions.
Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery
Da, Chang (McKetta Department of Chemical Engineering) | Xue, Zheng (McKetta Department of Chemical Engineering) | Worthen, Andrew J. (McKetta Department of Chemical Engineering) | Qajar, Ali (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Prodanovic, Maลกa (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Johnston, Keith P. (McKetta Department of Chemical Engineering)
Abstract CO2/water foams are of interest for mobility control in CO2 EOR and as energized fracture fluids, or hybrid processes that combine aspects of both processes. In fracturing applications, it would be desirable to lower the water level as much as possible to minimize the production of wastewater and formation damage. It is challenging to stabilize ultra dry foams with extremely high internal phase gas fraction given the high capillary pressure and the rapid drainage rate of the lamellae between the gas bubbles. However, we demonstrate that these ultra dry CO2-in-water foams may be stabilized with surfactants that form viscoelastic wormlike micelles in the aqueous phase. These wormlike micelles are formed by tuning the surfactant packing parameter with electrolytes or a second oppositely-charged surfactant to stabilize ultradry CO2-in-water foams with foam qualities as high as 0.98 and apparent viscosities more than 100 cP up to 90 ยฐC. Applicability of these foams for improved oil recovery is evaluated by running multiphase flow injection simulations in a case-study oil reservoir.
A Microfluidic Investigation of the Synergistic Effect of Nanoparticles and Surfactants in Macro-Emulsion Based EOR
XU, Ke (The University of Texas at Austin) | Zhu, Peixi (The University of Texas at Austin) | Tatiana, Colon (Polytechnic University of Puerto Rico) | Huh, Chun (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin)
Abstract Injecting oil-in-water (O/W) emulsions stabilized with nanoparticles or surfactants is a promising option for enhanced oil recovery (EOR) in harsh-condition reservoirs. Stability and rheology of flowing emulsion in porous media are key factors for the effectiveness of the EOR method. The objective of this study is to use microfluidics to (1) quantitatively evaluate the synergistic effect of surfactants and nanoparticles on emulsion's dynamic stability and how nanoparticles affects the emulsion properties, and (2) investigate how emulsion properties affect the sweep performance in emulsion flooding. A microfluidic device with well-defined channel geometry of a high-permeability pathway and multiple parallel low-permeability pathways was created to represent a fracture โ matrix dual-permeability system. Measurement of dropletsโ coalescence frequency during flow is used to quantify the dynamic stability of emulsions. A nanoparticle aqueous suspension (2 wt%) shows excellent ability to stabilize macro-emulsion when mixed with trace amount of surfactant (0.05 wt%), revealing a synergic effect between nanoparticles and surfactant. For a stable emulsion, it was observed that flowing emulsion droplets compress each other and then block the high-permeability pathway at a throat structure, which forces the wetting phase into low-permeability pathways. Droplet size shows little correlation with this blocking effect. Water content was observed much higher in the low-permeability pathways than in the high-permeability pathway, indicating different emulsion texture and viscosity in channels of different sizes. Consequently, the assumption of bulk emulsion viscosity in the porous medium is not applicable in the description and modeling of emulsion flooding process. Flow of emulsions stabilized by the nanoparticle-surfactant synergy shows droplet packing mode different from those stabilized by surfactant only at high local oil saturation region, which is attributed to the interaction among nanoparticles in the thin liquid film between neighboring oil-water interfaces. This effect is believed to be an important contributing mechanism for sweep efficiency attainable from nanoparticle-stabilized emulsion EOR process.
- North America > United States (0.69)
- North America > Canada > Alberta (0.28)
Experimental Studies and Modeling of Foam Hysteresis in Porous Media
Lotfollahi, Mohammad (The University of Texas at Austin) | Kim, Ijung (The University of Texas at Austin) | Beygi, Mohammad R. (The University of Texas at Austin) | Worthen, Andrew J. (The University of Texas at Austin) | Huh, Chun (The University of Texas at Austin) | Johnston, Keith P. (The University of Texas at Austin) | Wheeler, Mary F. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin)
Abstract The use of foam in gas enhanced oil recovery (EOR) processes has the potential to improve oil recovery by reducing gas mobility. Nanoparticles are a promising alternative to surfactants in creating foam in the harsh environments found in many oil fields. We conducted several CO2-in-brine foam generation experiments in Boise sandstones with surface-treated silica nanoparticle in high-salinity conditions. All the experiments were conducted at the fixed CO2 volume fraction (g = 0.75) and fixed flow rate which changed in steps. We started at low flow rates, increased to a medium flow rates followed by decreasing and then increasing into high flow rates. The steady-state foam apparent viscosity was measured as a function of injection velocity. The foam flowing through the cores showed higher foam generation and consequently higher apparent viscosity as the flow rate increased from low to medium and high velocities. At very high velocities, once foam bubbles were finely textured, the foam apparent viscosity was governed by foam shear-thinning rheology rather than foam creation. A noticeable "hysteresis" occurred when the flow velocity was initially increased and then decreased, implying multiple (coarse and strong) foam states at the same superficial velocity. A normalized generation function was combined with CMG-STARS foam model to cover the full spectrum of foam flow behavior observed during the experiments. The new foam model successfully captures foam generation and hysteresis trends observed in presented experiments in this study and other foam generation experiments at different operational conditions (e.g. fixed pressure drop at fixed foam quality, and fixed pressure drop at fixed water velocity) from the literature. The results indicate once foam is generated in porous media, it is possible to maintain strong foam at low injection rates. This makes foam more feasible in field applications where foam generation is limited by high injection rates (or high pressure gradient) that may only exist near the injection well. Therefore, understanding of foam generation, and foam hysteresis in porous media and accurate modeling of the process are necessary steps for efficient foam design in field.
- Asia (0.93)
- North America > United States > Texas (0.69)
- North America > United States > Idaho > Ada County > Boise (0.26)
Abstract Polymer flooding is a proven technology to improve sweep efficiency, while being one of the most economical enhanced oil recovery (EOR) processes. Partially hydrolyzed polyacrylamide (HPAM) has been widely used for polymer flooding. As the HPAM usage for EOR increases, the challenge of produced water management is also raised because residual HPAM in produced water could increase total chemical oxygen demand and unwanted viscosity in discharging or re-injecting the water. As the environmental standards and regulations get more stringent, it is difficult for the conventional methods to meet the requirement for discharging. Use of magnetic nanoparticles (MNPs) to remove contaminants from produced water is a promising way to treat produced water in an environmentally green way with minimal use of chemicals. The main attraction for MNPs is their quick response to move in a desired direction with application of external magnetic field. Another attraction of MNPs is versatile and efficient surface modification through suitable polymer coating, depending on the characteristics of target contaminants. In this study, we investigate the feasibility of polymer removal using surface-modified MNPs and regeneration of spent MNPs for multiple re-use. MNPs, in-house synthesized with prescribed surface coating, were superparamagnetic with an average individual particle size of ~10 nm. The removal efficiency of HPAM from water using the MNPs depended on the type and concentration of brines, concentration of amine-functionalized MNPs, surface coating of MNPs, molecular weight of polymer, and how many times the MNPs are regenerated and re-used. Virtually 100% removal of HPAM from water was feasible, depending on the reaction conditions. The regeneration of spent MNPs, using pH adjustment to recover the reactive sites, maintained above 90% removal efficiency for three-time repeatitive usages. The electrostatic attraction between negatively charged HPAM polymer and positively charged MNPs controls the attachment of MNPs to HPAM molecular chain; and the subsequent aggregation of the now neutralized MNP-attached HPAM plays a critical role for accelerated and efficient magnetic separation.
- Water & Waste Management > Water Management (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.52)
Nanoparticle-Stabilized Emulsions for Improved Mobility Control for Adverse-mobility Waterflooding
Kim, Ijung (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Worthen, Andrew J. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | Lotfollahi, Mohammad (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Johnston, Keith P. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | DiCarlo, David A. (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
Abstract The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions. Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer. Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective. In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
Nanoparticle-Stabilized Natural Gas Liquid-in-Water Emulsions for Residual Oil Recovery
Griffith, Nicholas (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Ahmad, Yusra (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Daigle, Hugh (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
Abstract Interest in silica nanoparticle-stabilized emulsions, especially those employing low-cost natural gas liquids (NGLs), has increased due to recent developments suggesting their use leads to improved conformance control and increased sweep efficiencies. When compared to conventional emulsion- stabilizing materials such as surfactants, nanoparticles are an inexpensive and robust alternative, offering stability over a wider range of temperature and salinity, while reducing environmental impact. Oil-in-water emulsions with an aqueous nanoparticle phase and either a pentane or butane oil phase at a 1:1 volume ratio were generated at varying salinities for the observations of several emulsion characteristics. The effects of salinity on the stability of silica nanoparticle dispersions and NGL emulsions were observed. Increasing the salinity of the aqueous nanoparticle phase resulted in an increase in effective nanoparticle size due to increased nanoparticle aggregation. Rheology tests and estimates of emulsion droplet sizes were performed. Shear-thinning behavior was observed for all emulsions. Furthermore, overall emulsion viscosity increased with salinity. Nanoparticle-stabilized liquid butane-in-water emulsions were also generated with varying brine concentrations; however, no rheology or droplet size measurements were made due to the volatility of these emulsions. Residual oil recovery coreflood experiments were conducted (using Boise Sandstone cores) with nanoparticle-stabilized pentane-in-water emulsions as injectant and light mineral oil as residual oil. A recovery of up to 82% residual oil was observed for these experiments. By continuously measuring the pressure drop across the core, a possible mechanism for enhanced oil recovery is proposed. Pentane emulsion coreflood tests indicated that at a slower injection rate, residual oil recovery increases. This contrasts viscous emulsion corefloods (mineral oil or Texaco white oil as the emulsion oil phase), where increasing the injection rate increases the residual oil recovery.
- North America > United States > Texas (0.29)
- North America > United States > Idaho > Ada County > Boise (0.25)