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Collaborating Authors
Alvarado, Vladimir
Effects of Carbonic Acid-Rock Interactions on CO2/Brine Multiphase Flow Properties in the Upper Minnelusa Sandstones
Kou, Zuhao (Department of Chemical Engineering, University of Wyoming (Equal Contributor)) | Wang, Heng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology) | Alvarado, Vladimir (Center for Economic Geology Research, University of Wyoming (Equal Contributor)) | Nye, Charles (Department of Chemical Engineering, University of Wyoming (Corresponding author)) | Bagdonas, Davin A. (Center for Economic Geology Research, University of Wyoming) | McLaughlin, J. Fred (Center for Economic Geology Research, University of Wyoming) | Quillinan, Scott Austin (Center for Economic Geology Research, University of Wyoming)
Summary Carbon dioxide (CO2) injection into a deep saline aquifer can dissolve into formation brine and generate carbonic acid. The resulting acid can drive fluid-rock geochemical reactions. The impact of these fluid-rock geochemical reactions on porosity, permeability, and multiphase flow responses is relevant to the determination of CO2 storage capacity of deep saline aquifers. In this research, carbonic acid flooding experiments were performed on core samples consisting of poorly sorted, quartz-rich sand with laminated bedding from a possible CO2 storage target in northwest Wyoming. Complementary pre- and post-injection porosity and permeability, thin-section, Brunauer-Emmett-Teller (BET) surface area, mercury intrusion capillary pressure (MICP), and time-domain nuclear magnetic resonance (TD-NMR) measurements were conducted. Overall, both core porosity and permeability increased after a 7-day carbonic acid injection, from 6.2 to 8.4% and 1.6 to 3.7 md, respectively. We attributed these changes to carbonate mineral dissolution, which was evidenced by the effluent brine geochemistry, pore-throat size distribution (PTSD), and BET surface area. To be more specific, within the more-permeable section of core samples containing larger pore size, the permeability increment is apparent due to dolomite mineral grains and cements dissolution. However, for the lower-permeability section corresponding to the smaller pore size, mineral precipitation possibly lessened dissolution effects, leading to insignificant petrophysical properties changes. Consequently, the observed heterogeneous carbonic acid-rock interactions resulted in alterations of CO2/brine relative permeability (i.e., the initial CO2 saturation decreased and the CO2 flow capacity was enhanced). This research provides a fundamental understanding regarding effects of fluid-rock reactions on changes in static and multiphase flow properties of eolian sandstones, which lays the foundation for more accurate prediction/simulation of CO2 injection into deep saline aquifers.
- North America > United States > Wyoming (0.34)
- North America > United States > Montana (0.28)
- Research Report > New Finding (0.69)
- Research Report > Experimental Study (0.46)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.49)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- (5 more...)
Effects of Carbonic Acid-Rock Interactions on CO2/Brine Multiphase Flow Properties in the Upper Minnelusa Sandstones
Kou, Zuhao (Department of Chemical Engineering, University of Wyoming (Equal contributor)) | Wang, Heng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology and Center for Economic Geology Research, University of Wyoming (Equal contributor)) | Alvarado, Vladimir (Department of Chemical Engineering, University of Wyoming (Corresponding author)) | Nye, Charles (Center for Economic Geology Research, University of Wyoming) | Bagdonas, Davin A. (Center for Economic Geology Research, University of Wyoming) | McLaughlin, J. Fred (Center for Economic Geology Research, University of Wyoming) | Quillinan, Scott Austin (Center for Economic Geology Research, University of Wyoming)
Summary Carbon dioxide (CO2) injection into a deep saline aquifer can dissolve into formation brine and generate carbonic acid. The resulting acid can drive fluid-rock geochemical reactions. The impact of these fluid-rock geochemical reactions on porosity, permeability, and multiphase flow responses is relevant to the determination of CO2 storage capacity of deep saline aquifers. In this research, carbonic acid flooding experiments were performed on core samples consisting of poorly sorted, quartz-rich sand with laminated bedding from a possible CO2 storage target in northwest Wyoming. Complementary pre- and post-injection porosity and permeability, thin-section, Brunauer-Emmett-Teller (BET) surface area, mercury intrusion capillary pressure (MICP), and time-domain nuclear magnetic resonance (TD-NMR) measurements were conducted. Overall, both core porosity and permeability increased after a 7-day carbonic acid injection, from 6.2 to 8.4% and 1.6 to 3.7 md, respectively. We attributed these changes to carbonate mineral dissolution, which was evidenced by the effluent brine geochemistry, pore-throat size distribution (PTSD), and BET surface area. To be more specific, within the more-permeable section of core samples containing larger pore size, the permeability increment is apparent due to dolomite mineral grains and cements dissolution. However, for the lower-permeability section corresponding to the smaller pore size, mineral precipitation possibly lessened dissolution effects, leading to insignificant petrophysical properties changes. Consequently, the observed heterogeneous carbonic acid-rock interactions resulted in alterations of CO2/brine relative permeability (i.e., the initial CO2 saturation decreased and the CO2 flow capacity was enhanced). This research provides a fundamental understanding regarding effects of fluid-rock reactions on changes in static and multiphase flow properties of eolian sandstones, which lays the foundation for more accurate prediction/simulation of CO2 injection into deep saline aquifers.
- North America > United States > Wyoming (0.34)
- North America > United States > Montana (0.28)
- Research Report > New Finding (0.69)
- Research Report > Experimental Study (0.46)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.49)
- Oceania > Australia > Queensland > Surat Basin (0.99)
- Oceania > Australia > New South Wales > Surat Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- (5 more...)
Abstract Injection of a generic naphthenic acid blend in waterflooding experiments has been shown to enhance oil recovery. A brine-oil interfacial response upon addition of organic acids has also been recorded and linked to the improved recovery response. The purpose of this work is to analyze the effect of several individual naphthenic acids on the oil-water interface and thereby determine which structure of acids is most potentially influential in improving oil recovery. Acids were selected based on water solubility and structure; analyses were conducted on several molecular structural characteristics to assess the relationship to interfacial responses. Based on the observed fluid-fluid interactions and the likelihood that the acid blend in previous work contained some of the acids studied, we propose a causative connection between the addition of organic acid blends and the recovery efficiency.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
Interfacial Viscoelasticity of Crude Oil/Brine: An Alternative Enhanced-Oil-Recovery Mechanism in Smart Waterflooding
Bidhendi, Mehrnoosh Moradi (University of Wyoming) | Garcia-Olvera, Griselda (University of Wyoming) | Morin, Brendon (University of Wyoming) | Oakey, John S. (University of Wyoming) | Alvarado, Vladimir (University of Wyoming)
Summary Injection of water with a designed chemistry has been proposed as a novel enhanced-oil-recovery (EOR) method, commonly referred to as low-salinity (LS) or smart waterflooding, among other labels. The multiple names encompass a family of EOR methods that rely on modifying injection-water chemistry to increase oil recovery. Despite successful laboratory experiments and field trials, underlying EOR mechanisms remain controversial and poorly understood. At present, the vast majority of the proposed mechanisms rely on rock/fluid interactions. In this work, we propose an alternative fluid/fluid interaction mechanism (i.e., an increase in crude-oil/water interfacial viscoelasticity upon injection of designed brine as a suppressor of oil trapping by snap-off). A crude oil from Wyoming was selected for its known interfacial responsiveness to water chemistry. Brines were prepared with analytic-grade salts to test the effect of specific anions and cations. The brinesโ ionic strengths were modified by dilution with deionized water to the desired salinity. A battery of experiments was performed to show a link between dynamic interfacial viscoelasticity and recovery. Experiments include double-wall ring interfacial rheometry, direct visualization on microfluidic devices, and coreflooding experiments in Berea sandstone cores. Interfacial rheological results show that interfacial viscoelasticity generally increases as brine salinity is decreased, regardless of which cations and anions are present in brine. However, the rate of elasticity buildup and the plateau value depend on specific ions available in solution. Snap-off analysis in a microfluidic device, consisting of a flow-focusing geometry, demonstrates that increased viscoelasticity suppresses interfacial pinch-off, and sustains a more continuous oil phase. This effect was examined in coreflooding experiments with sodium sulfate brines. Corefloods were designed to limit wettability alteration by maintaining a low temperature (25ยฐC) and short aging times. Geochemical analysis provided information on in-situ water chemistry. Oil-recovery and pressure responses were shown to directly correlate with interfacial elasticity [i.e., recovery factor (RF) is consistently greater the larger the induced interfacial viscoelasticity for the system examined in this paper]. Our results demonstrate that a largely overlooked interfacial effect of engineered waterflooding can serve as an alternative and more complete explanation of LS or engineered waterflooding recovery. This new mechanism offers a direction to design water chemistry for optimized waterflooding recovery in engineered water-chemistry processes, and opens a new route to design EOR methods.
- North America > United States > California (0.46)
- North America > United States > Pennsylvania (0.34)
- North America > United States > Texas (0.28)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geochemistry (0.68)
- Geology > Rock Type > Sedimentary Rock (0.49)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
Abstract Smart waterflooding in hydrocarbon reservoirs has been a subject of intense speculation. Several recovery mechanisms have been proposed, including wettability alteration toward water-wetness. In contrast, the role of fluid-fluid interactions has been overlooked. In this study, we evaluate rock-fluid interactions in connection with the observed increased oil recovery under smart waterflooding conditions. Focus is placed on fluid-fluid interfacial rheological effects resulting from adjusting the injection brine ionic profile. Berea sandstone cores were aged at high oil saturation and subsequently allowed imbibed spontaneously with a number of selected brines to investigate the impact of sulfate concentration and to compare responses to low- vs. high-salinity brines. For each sample, a sister end trim was aged and exposed to the respective fluids to measure oil-water contact angle. Supplementary, we measured zeta potential at the rock-fluids interfaces to examine the effect of low-salinity brine on the electrical double-layer expansion. The spinning drop and pendant drop methods were used for interfacial rheological measurements, to obtain interfacial visco-elastic moduli and interfacial tension, respectively. Spontaneous imbibition results showed significantly higher oil recoveries for brines with greater sulfate concentrations or lower salinities. However, the rates of imbibition, which reflect the wettability of the rock surfaces, did not differ significantly. Contact angle measurements also correlated with the results of spontaneous imbibition. Measurements showed a slight change from strongly oil-wet to intermediate-wet. Zeta potential results indicate a possible expansion of the electrical double layer at the rock-brine interface, and thus a minor change of wettability. It was noticed that even at intermediate-wet conditions, oil droplets were still attached to surface. We also observed that when the relatively small oil droplets coalesce on the surface, the newly formed oil droplet detached more readily. Changes in wettability cannot sufficiently explain the observed increase in oil recovery. It is believed that other factors such as interfacial visco-elasticity could affect capillary-driven interactions in the pore space. The spinning drop measurements show that by increasing the sulfate concentrations or decreasing salinity, the crude oil-water visco-elasticity increases, as previously shown in our group through interfacial shear rheological measurements. The wettability observations along with the interfacial rheology findings provide a more satisfactory explanation of the recovery trends observed. Our findings indicate that during smart waterflooding processes, wettability alteration is unlikely the sole mechanism at play. After wettability alteration has taken place, the higher crude oil-water visco-elasticity due to presence sulfate ions or low-salinity brine, allowed oil droplets to coalesce forming a continuous oil banks and contributing to more oil recovery.
- North America > United States > West Virginia (0.61)
- North America > United States > Pennsylvania (0.61)
- North America > United States > Ohio (0.61)
- North America > United States > Kentucky (0.61)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Mineral > Silicate > Phyllosilicate (0.46)
Chemical enhanced-oil recovery has been applied successfully in reservoirs with mild salinity and temperature conditions. Offshore reservoirs challenge chemical flooding, e.g. low-tension and foam flooding, because of the combined hardness and salinity of seawater along with characteristics of the reservoir connate brine. These physico-chemical conditions impose severe limitations to adequate phase behavior for most commercial surfactants. The purpose of the research described herein is to analyze surfactant phase behavior for scenarios with seawater as the main carrying fluid for surfactant systems. Thermal stability and solubility were analyzed for a number of surfactants provided by two companies. Tests were conducted using a range of simulated connate brines and seawater compositions. Critical Micelle Concentration (CMC) values were estimated using a Nuclear Magnetic Resonance (NMR) protocol developed in our laboratory, recently published (Garcia-Olvera et al., 2016). NMR data were taken from solvents and co-solvents to analyze individual components in chemical blends. Phase behavior experiments were run to determine which blend composition and brine salinity would enable the desired phase behavior. A medium-gravity oil thoroughly studied in our lab was selected for phase behavior studies. Finally, a coreflood was conducted on a subset of surfactants to evaluate the additional oil recovery for one of the evaluated scenarios. Some surfactants were disregarded for further analysis, due to their lack of thermal stability (dropout from solution was observed). In some cases, co-solvents were added to increase solubility in surfactant blends with a high divalent ion content, which in some cases was insufficient to stabilize the blends. Phase behavior experiments show that some surfactants did not yield Type III microemulsions, and therefore were disregarded for low-tension flooding applications. NMR data for surfactants and co-surfactants yielded good results even when the NMR spectra for different blend components overlaid significantly. Softening of high-salinity brines indeed improved micro-emulsion volume in the phase behavior tests, as demonstrated in the coreflood. However, this strategy is shown through geochemical analysis to be risky for more reactive lithologies, where dissolution and precipitation events are prompted by reduction in hardness in the injection brine. Our use of an advanced spectroscopic technique (NMR) provides a more quantitative way of determining constraints associated with solubility limits and poor phase behavior under physico-chemical conditions of harsher environments. Geochemical considerations are important for mitigation strategies in reactive lithologies.
- Asia (1.00)
- North America > United States > Texas (0.68)
- North America > Mexico (0.67)
- Research Report > Experimental Study (0.48)
- Research Report > New Finding (0.46)
- Geology > Geological Subdiscipline > Geochemistry (0.74)
- Geology > Rock Type > Sedimentary Rock (0.70)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Bighorn Basin > Cottonwood Creek Field > Phosphoria Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Low-salinity waterflooding has been portrayed as an effective enhanced-oil recovery technology. Despite compelling laboratory and field evidence of its potential, the underlying mechanisms still remain controversial. In this study, the enhanced-oil recovery mechanisms are investigated considering a distinct interfacial effect, i.e. water-crude oil interfacial viscoelasticity, through analysis of capillary hysteresis. An experimental setup with an oil-wet and a water-wet media on each end face of the core sample was utilized to capture capillary and rock electrical properties hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method were implemented to accelerate measurements. Two experiments were conducted on Minnelusa formation rock samples and TC crude oil, at low temperature (30 ยฐC) and without any significant aging as to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. It is found that the dynamic-static method with a ceramic disk, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short 1" long core samples, allows one to capture the correct envelopes of the capillary pressure curves and save ~ 30% of the total time; a thin membrane is anticipated to save ~90% with respect to traditional quasi-static porous plate method. The capillary hysteresis experiments at low temperature prove that low-salinity brine is able to suppress capillary hysteresis. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. In addition, we show that wettability plays an essential role on electrical resistivity and the more oil-wet, the more hysteresis occurs, namely that resistivity values in imbibition are higher than those in drainage. The findings in this paper demonstrate that low-salinity waterflooding can still increase oil recovery even in the absence of wettability alteration.
Abstract Recovery from oil reservoirs could be improved by lowering the injection water salinity or by modifying the water injection chemistry. This has been proposed as a way to increase rock water-wetness. However, we have observed that the presence of sulfate anions in the aqueous phase can change the crude oil-water interfacial rheology drastically, and as a result, the oil recovery factor could be increased solely by alteration of fluid-fluid interactions. The purpose of this research is to show the effect of sulfate anion concentration in seawater injection on oil production through coreflooding results at low temperature. Interfacial rheological experiments were run with several crude oils and modified seawater to see the effect of different ions on visco-elasticity of the crude oil-brine interface using an AR-G2 rheometer with a dual-wall ring fixture. Based on previous experimental results, carefully selected coreflooding experiments were run to evaluate differential pressure and oil recovery for each selected brine. Coreflooding experiments used Indiana Limestone at 25ยฐC without aging to minimize changes in rock wettability. The interfacial rheological results show that the visco-elasticity of the crude oil-brine interface is higher for a low-salinity brine compared to a higher-salinity one when individual salts are used, e.g. NaCl or Na2SO4. The difference is more pronounced if ultralow salinities are compared. For the cases with salinity values similar to that of seawater, the effect of sulfate concentration in water on interfacial visco-elasticity is more noticeable. Coreflooding results show that brines with a higher visco-elasticity, corresponding to a higher sulfate concentration in the water injected, yield higher oil recovery factor that those with lower visco-elasticity, including the experiments with salinity lower than 50% of that of seawater. Brine-rock reactions were geochemically simulated to prevent injection conditions that could cause formation damage. Additionally, pH, electrical conductivity and total dissolved solid (TDS) were analyzed in the effluents. Results show that for the model rock used, brine composition does not change significantly from contact with rock surfaces. Since wettability alteration was minimized by use of low-temperature and short ageing time, recovery correlates better with changes in interfacial rheology. For results showing an apparent lack of correspondence with the interfacial rheological response, arguments based on ganglia dynamics might shed light on the observed recovery outcome. Our findings reveal that the injection of water with sulfate can modify the fluid-fluid interactions and consequently the final oil recovery, so in some cases, low-salinity brine injection is not necessarily conducive to an increment in oil production. Findings also indicate that more characterization of the brine-crude oil interface should be carefully conducted as part of the screening of adjusted brine chemistry waterflooding.
- Europe (1.00)
- Asia (1.00)
- North America > United States > California (0.46)
- (2 more...)
- Geology > Mineral > Sulfate (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.61)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Garoupa Cluster > Namorado Field (0.99)
- South America > Brazil > Campos Basin (0.99)
Abstract Drawing on techniques from both petroleum engineering and economics, we analyze how oil fields that use CO2 injection to enhance oil recovery (CO2-EOR projects) are likely to respond to incentives that promote CO2 sequestration. Most engineering studies that have examined how oil-field operators should "co-optimize" oil recovery and CO2 sequestration use sophisticated reservoir models, but ad hoc economics. Conversely, a study by Leach et al. (2011), which to date is the only rigorous economic study of co-optimization, uses sophisticated economics, but an ad hoc reservoir model. Our study bridges the gap between these studies, by applying Leach et al.'s analysis to dynamic reservoir-simulation models of two different oil fields. We find that, even though Leach et al.'s assumptions about how a reservoir responds to CO2 injection are quite far off the mark quantitatively, their main findings hold up remarkably well qualitatively.
- North America > United States > Wyoming > Powder River Basin > Salt Creek Field (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Wall Creek Formation (0.99)
- North America > United States > Wyoming > Powder River Basin > NPR-3 > Teapot Dome Field > Wall Creek Formation (0.99)
- (9 more...)
Abstract Low salinity waterflooding is a promising Improved Oil Recovery (IOR) process showing growing activity since discovery. However, incremental recovery over traditional waterflooding varies significantly. Numerous investigations have attempted to prove or disprove recovery mechanisms associated to this process. In our earlier research, we proposed that buildup of the crude oil-brine film viscoelasticity leads to suppression of trapping mechanisms during low-salinity waterflooding. We also advanced the idea that film response depends upon combined characteristics of both crude oil and water. In this paper, interfacial viscoelasticity measurements were conducted on several Wyoming crude oils as well as processed versions of the same oils with selected asphaltene content. Dual-wall ring shear rheology and pendant-drop dilational rheology were run to investigate the connection between polar content in the oil and interfacial viscoelastic response. To further investigate the connection between the interface viscoelasticity and low-salinity waterflooding mechanisms, coreflooding experiments intended to minimize geochemical events during flooding were completed using Berea sandstone. Oil recovery and pressure responses were monitored as well. Film viscoelasticity results turned out consistent with our hypothesis, namely that high content of polar components leads to high viscoelasticity of the crude oil-water interfacial film. Carefully selected coreflooding experiments were run and these results were combined with our earlier ones to unveil recovery trends. Our observations show that a good relationship exists between polar component content and interfacial viscoelasticity, and consequently with oil recovery factor, but outlying results, though favoring low-salinity waterflooding, indicate that a more complex set of interactions need to be further investigated. The conclusions of our work support an additional mechanism for low salinity waterflooding that should improve industry's ability to select candidates for this process by directing fluid-fluid characterization efforts not frequently executed at present.
- North America > United States > California (0.46)
- North America > United States > Texas (0.46)
- Geology > Rock Type > Sedimentary Rock (0.67)
- Geology > Geological Subdiscipline (0.49)
- Geology > Mineral (0.47)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- North America > United States > Kansas > State Field (0.97)