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Guangwei Ren
Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, TX, USA

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Journal article
Published: 03 April 2021 in Fuel
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Low-Tension gas (LTG), as an emerging technique, attempts to synergize oil desaturation by microemulsion and mobility control via foam, which is an ideal alternative wherever other tertiary recovery techniques are technically limited. Previously, high oil recovery was achieved with proposed formula and novel injection strategy under harsh conditions (190,000 ppm, 85 °C) [53] with N2 and dead oil, which were robust to wide reservoir scenes (0.5 ft/d, 7 md) [54]. Here, more practical field scenarios are examined with methane and live oil for the first time facilitated by auxiliary tests of bulk foam stability, microemulsion viscosities and surfactant retention. Microemulsion phase behaviors are probed for both N2 and CH4 under reservoir pressure (1200 psi, 85 °C) in sequence to distinguish the impacts of pressure and solution gas. Therewith, pressure drop, effluent salinity and oil recovery are recorded to analyze effects of mobility control, gas type (N2 or CH4) and oil condition (dead or live) through multiple corefloodings stepwise. It is found higher pressure and solubilized methane impose limited impacts on current microemulsion phase behaviors. The developed formula and novel injection strategy satisfy the requirements of mobility control and oil desaturation, through the balance between foam stability and relatively low IFT. The surfactant retention is 0.162 mg/g during LTG process. Neither gas type or oil condition exerts discernible influences indicated by similarly high oil recoveries around 90%. The findings here promote the field implementation of this novel technique for both greenhouse gas utilization and enhanced oil recovery.

ACS Style

Guangwei Ren; Quoc P. Nguyen. In-depth experimental investigations of low-tension gas technique with methane and live oil in high salinity and high temperature sandstone reservoirs. Fuel 2021, 297, 120731 .

AMA Style

Guangwei Ren, Quoc P. Nguyen. In-depth experimental investigations of low-tension gas technique with methane and live oil in high salinity and high temperature sandstone reservoirs. Fuel. 2021; 297 ():120731.

Chicago/Turabian Style

Guangwei Ren; Quoc P. Nguyen. 2021. "In-depth experimental investigations of low-tension gas technique with methane and live oil in high salinity and high temperature sandstone reservoirs." Fuel 297, no. : 120731.

Journal article
Published: 02 March 2021 in Sustainable Chemistry
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Supercritical CO2 (ScCO2) emulsion has attracted lots of attention, which could benefit both climate control via CO2 storage and industry revenue through significantly increased oil recovery simultaneously. Historically, aqueous soluble surfactants have been widely used as stabilizers, though they suffer from slow propagation, relatively high surfactant adsorption and well injectivity issues. In contrast, the CO2-soluble surfactants could improve the emulsion performance remarkably, due to their CO2-philicity. Here, comprehensive comparison studies are carried out from laboratory experiments to field scale simulations between a commercially available aqueous soluble surfactant (CD 1045) and a proprietary nonionic CO2-philic surfactant whose solubility in ScCO2 and partition coefficient between ScCO2/Brine have been determined. Surfactant affinity to employed oil is indicated by a phase behavior test. Static adsorptions on Silurian dolomite outcrop are conducted to gain the insights of its electro-kinetic properties. Coreflooding experiments are carried out with both consolidated 1 ft Berea sandstone and Silurian dolomite to compare the performances as a result of surfactant natures under two-phase conditions, while harsher conditions are examined on fractured carbonate with presence of an oleic phase. Moreover, the superiorities of ScCO2 foam with CO2-philic surfactant due to dual phase partition capacity are illustrated with field scale simulations. ScCO2 and WAG injections behaviors are used as baselines, while the performances of two types of CO2 emulsions are compared with SAG injection, characterized by phase saturations, CO2 storage, oil production, CO2 utilization ratio and pressure distribution. A novel injection strategy, named CO2 continuous injection with dissolved surfactant (CIDS), which is unique for a CO2-philic surfactant, is also studied. It is found that the CO2-soluble surfactant displays much lower oil affinity and adsorption on carbonate than CD 1045. Furthermore, in a laboratory scale, a much higher foam propagation rate is observed with the novel surfactant, which is mainly ascribed to its CO2 affinity, assisted by the high mobility of the CO2 phase. Field scale simulations clearly demonstrate the potentials of CO2 emulsion on CO2 storage and oil recovery over conventional tertiary productions. Relative to traditional aqueous soluble surfactant emulsion, the novel surfactant emulsion contributes to higher injectivity, CO2 storage capability, oil recovery and energy utilization efficiency. The CIDS could further reduce water injection cost and energy consumption. The findings here reveal the potentials of further improving CO2 storage and utilization when applying ScCO2-philic surfactant emulsion, to compromise both environmental and economic concerns.

ACS Style

Guangwei Ren; Bo Ren; Songyan Li; Chao Zhang. Unlock the Potentials to Further Improve CO2 Storage and Utilization with Supercritical CO2 Emulsions When Applying CO2-Philic Surfactants. Sustainable Chemistry 2021, 2, 127 -148.

AMA Style

Guangwei Ren, Bo Ren, Songyan Li, Chao Zhang. Unlock the Potentials to Further Improve CO2 Storage and Utilization with Supercritical CO2 Emulsions When Applying CO2-Philic Surfactants. Sustainable Chemistry. 2021; 2 (1):127-148.

Chicago/Turabian Style

Guangwei Ren; Bo Ren; Songyan Li; Chao Zhang. 2021. "Unlock the Potentials to Further Improve CO2 Storage and Utilization with Supercritical CO2 Emulsions When Applying CO2-Philic Surfactants." Sustainable Chemistry 2, no. 1: 127-148.

Research article
Published: 10 September 2020 in Energy & Fuels
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Experimentally, CO2 soluble surfactant foams have displayed significant superiorities over conventional aqueous soluble one in promoting foam strength, accelerating surfactant/foam propagation, and enhancing oil recovery. It was observed the eventual foam performances could be the counterbalance results of faster foam propagation and reduced local pressure gradient characterized by the magnitudes of partition coefficient between CO2/aqueous, which was designated as spreading effect. This paper aims to numerically investigate the key aspects influencing CO2 soluble surfactant foams performances in a homogeneous analogue system, with respect to injection periods, critical foaming concentration and surfactant adsorption determined by surfactant structure, and injection foam quality. It is found that stepwise oil production consists of three stages in sequence attributed to the distinct recovery mechanisms. The optimal partition coefficient for a studied system cannot be derived directly by the absolute value of surfactant partition coefficient, but is affected by the employed rock, fluids, and injection conditions. The less EO group endues higher partition capacity and adsorption on rock surface simultaneously. The tradeoff results in the least adverse impact for high partition capacity surfactant even though the optimal value shifts to the lower end. The impacts of injection foam quality are the combination of total injection rate, amount of injection fluids, miscibility between Gas/Oil and surfactant spreading. The values of surfactant partition coefficient determine the eventual impacts of promoted or suppressed spreading effect. The studies in this article promote the understandings of this novel technology to maximize the oil recovery as well as CO2 utilization.

ACS Style

Guangwei Ren. Numerical Assessments of Key Aspects Influencing Supercritical CO2 Foam Performances when Using CO2-Soluble Surfactants. Energy & Fuels 2020, 34, 12033 -12049.

AMA Style

Guangwei Ren. Numerical Assessments of Key Aspects Influencing Supercritical CO2 Foam Performances when Using CO2-Soluble Surfactants. Energy & Fuels. 2020; 34 (10):12033-12049.

Chicago/Turabian Style

Guangwei Ren. 2020. "Numerical Assessments of Key Aspects Influencing Supercritical CO2 Foam Performances when Using CO2-Soluble Surfactants." Energy & Fuels 34, no. 10: 12033-12049.

Journal article
Published: 29 May 2020 in Fuel
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Supercritical CO2 (ScCO2) foam could benefit both industry revenue generation through EOR and climate control with CO2 storage/utilization. Relative to aqueous soluble surfactants, it has been experimentally observed that CO2-philic surfactants accelerated foam propagation and enhanced oil recovery significantly. It is desired to probe additional potential superiorities with presence of gravity under reservoir conditions. In this paper, comprehensive numerical investigations are conducted to compare the ScCO2 foam performances with both types of surfactants under variable injection strategies in a homogeneous reservoir. Both constant rate and pressure constraints are examined, where impacts of slug size, volumetric injection phase ratio, perforation location, and phase injection portion are probed. For all tested injection strategies, the novel foam outperforms conventional one with higher oil recovery, injectivity, and injection fluids (surfactant/CO2) utilization efficiencies. The dual partition capacity of CO2-philic surfactant could not only improve the injectivity but also divert CO2 effectively. The novel injection strategy with dissolved CO2-soluble surfactant outperforms others. Also, the novel foam is not sensitive to injection parameter values. Constant pressure injection could provide alike performances as those under constant rate constraint if injection fluids conservations are employed, which revises prior conclusions. The inherent dual phase partition capacity of CO2 soluble surfactant predominates in fighting gravity segregation and enhancing foam performances, which replaces prior external criteria with aqueous soluble surfactants through injection strategy, constraint and gravity segregation length. The findings here assign significant flexibility during field operation. The comparisons improve understandings of this novel technology and provide guidance for field implementation.

ACS Style

Guangwei Ren. Assess the potentials of CO2 soluble surfactant when applying supercritical CO2 foam. Part I: Effects of dual phase partition. Fuel 2020, 277, 118086 .

AMA Style

Guangwei Ren. Assess the potentials of CO2 soluble surfactant when applying supercritical CO2 foam. Part I: Effects of dual phase partition. Fuel. 2020; 277 ():118086.

Chicago/Turabian Style

Guangwei Ren. 2020. "Assess the potentials of CO2 soluble surfactant when applying supercritical CO2 foam. Part I: Effects of dual phase partition." Fuel 277, no. : 118086.

Journal article
Published: 18 February 2020 in Fuel
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Low tension gas (LTG) process attempts to employ microemulsion (MI) and foam to enhance oil recovery (EOR). It is challenging to model surfactant phase behavior as a function of salinity for commercially available simulators since they lack the capability to explicitly represent MI properties. In this paper, a novel approach is developed to simultaneously model foam flow and surfactant/oil/brine key characteristics, using the general framework of CMG/STARS. Measured phase behavior data is transferred into k-value based relationships with multi-components oleic phase, based on which phase viscosities are calculated with non-linear mixing equation as function of different key components. Winsor Type phase variations are tracked by a pseudo-component generated by kinetic reactions, as another invention here. The mobility control by foam is fulfilled by the novel bubble dispersion model when increasing aqueous phase viscosity through bubble characteristics. Investigations of phase viscosities, IFT and compositions in 1D and 2D section models show that the developed methodology correctly accounts for surfactant solution desaturation in matrix and for mobility control by foam flow in the fractures. As such, the developed techniques provide a methodology to model LTG process in naturally fractured reservoirs within the framework of commercially available simulators along with their limited functionalities.

ACS Style

Guangwei Ren. A novel technique to simulate low tension gas (LTG) process in fractured reservoirs with commercially available simulator. Fuel 2020, 267, 117207 .

AMA Style

Guangwei Ren. A novel technique to simulate low tension gas (LTG) process in fractured reservoirs with commercially available simulator. Fuel. 2020; 267 ():117207.

Chicago/Turabian Style

Guangwei Ren. 2020. "A novel technique to simulate low tension gas (LTG) process in fractured reservoirs with commercially available simulator." Fuel 267, no. : 117207.

Journal article
Published: 20 May 2019 in Journal of CO2 Utilization
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Experimental studies have showed that CO2 soluble surfactants were more effective than aqueous soluble surfactant as supercritical CO2 foaming agent in fractured carbonate cores, in terms of higher foam strengths and oil recoveries. This paper aims to reveal the potential causes responsible to those superiorities and probe the impacts of key aspects during this complex process. Variable surfactants are examined to investigate the presence of optimal partition coefficient. The impact of surfactant structure on critical foaming concentration is also studied. Effect of reservoir pressure is investigated through stepwise independent manipulations attempting to decouple its influences on miscibility between CO2/oil, free gas phase availability and surfactant partition coefficient between CO2/brine. Effect of injection foam quality (gas volumetric fraction) is probed at constant liquid injection rate. It is found that the optimal partition coefficient for selected system is affected by multiple practical conditions including injection periods and surfactant structure relevant model parameters, but not determined by absolute coefficient values. The results of increasing system pressure and injection foam quality are combination of multiple aspects, including miscibility between CO2/Oil, local pressure drop, foam apparent viscosity, among of CO2 injection, gaseous CO2 available for surfactant delivery, and interplay between faster surfactant propagation and reduced local pressure gradient (“spreading” effect). The contribution of promoted or suppressed spreading effect could depend on magnitude of individual partition coefficient. The findings here reveal the complex interactions of multiple key aspects affecting CO2 soluble surfactant foams performance and promote the understandings to apply this novel technology in fractured systems.

ACS Style

Guangwei Ren; Wei Yu. Numerical investigations of key aspects influencing CO2 foam performance in fractured carbonate system using CO2 soluble surfactants. Journal of CO2 Utilization 2019, 33, 96 -113.

AMA Style

Guangwei Ren, Wei Yu. Numerical investigations of key aspects influencing CO2 foam performance in fractured carbonate system using CO2 soluble surfactants. Journal of CO2 Utilization. 2019; 33 ():96-113.

Chicago/Turabian Style

Guangwei Ren; Wei Yu. 2019. "Numerical investigations of key aspects influencing CO2 foam performance in fractured carbonate system using CO2 soluble surfactants." Journal of CO2 Utilization 33, no. : 96-113.

Journal article
Published: 01 October 2018 in Journal of Petroleum Science and Engineering
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Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions. A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 °C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water. RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam. These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.

ACS Style

Guangwei Ren; Quoc P. Nguyen; Hon Chung Lau. Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants. Journal of Petroleum Science and Engineering 2018, 169, 277 -296.

AMA Style

Guangwei Ren, Quoc P. Nguyen, Hon Chung Lau. Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants. Journal of Petroleum Science and Engineering. 2018; 169 ():277-296.

Chicago/Turabian Style

Guangwei Ren; Quoc P. Nguyen; Hon Chung Lau. 2018. "Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants." Journal of Petroleum Science and Engineering 169, no. : 277-296.

Original paper
Published: 28 March 2017 in Petroleum Science
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The ability of a novel nonionic CO2-soluble surfactant to propagate foam in porous media was compared with that of a conventional anionic surfactant (aqueous soluble only) through core floods with Berea sandstone cores. Both simultaneous and alternating injections have been tested. The novel foam outperforms the conventional one with respect to faster foam propagation and higher desaturation rate. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, has been tested in the laboratory. Strong foam presented without delay. It is the first time the measured surfactant properties have been used to model foam transport on a field scale to extend our findings with the presence of gravity segregation. Different injection strategies have been tested under both constant rate and pressure constraints. It was showed that novel foam outperforms the conventional one in every scenario with much higher sweep efficiency and injectivity as well as more even pressure redistribution. Also, for this novel foam, it is not necessary that constant pressure injection is better, which has been concluded in previous literature for conventional foam. Furthermore, the novel injection strategy, CO2 continuous injection with dissolved CO2-soluble surfactant, gave the best performance, which could lower the injection and water treatment cost.

ACS Style

Guangwei Ren; Quoc P. Nguyen. Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs. Petroleum Science 2017, 14, 330 -361.

AMA Style

Guangwei Ren, Quoc P. Nguyen. Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs. Petroleum Science. 2017; 14 (2):330-361.

Chicago/Turabian Style

Guangwei Ren; Quoc P. Nguyen. 2017. "Understanding aqueous foam with novel CO2-soluble surfactants for controlling CO2 vertical sweep in sandstone reservoirs." Petroleum Science 14, no. 2: 330-361.

Journal article
Published: 19 May 2013 in SPE Journal
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Summary This paper presents a systematic study of the effect of surfactant partitioning between supercritical carbon dioxide (SCCO2) and water on surfactant transport and foam propagation during a two-phase flow. A series of corefloods was conducted on Silurian dolomite cores with different nonionic and anionic surfactants that represent respective wide ranges of partition coefficients and solubility in SCCO2. Foam robustness (i.e., rate of foam development) and displacement efficiency were related to these surfactant properties. Coreflood results and all measured surfactant properties were used in a commercial reservoir simulator to determine the variation of the surfactant-partitioning effect from laboratory to field scale. The optimization of the surfactant-partition coefficient for field-scale foam process was performed with different injection strategies. The results from this study enable us to tailor the properties of CO2-soluble surfactants (i.e., partition coefficients) to a wide range of reservoir conditions and optimal injection strategies. The understanding of the surfactant-partitioning effect is also important in overcoming technical challenges encountered in the injection of surfactant in CO2. The partition between CO2 and water phases was much more sensitive to surfactant structure than temperature and pressure. Strong foam development was observed for all nonionic and anionic surfactants, whereas an increase in surfactant-partition coefficient lowered the rate of foam propagation. Field-scale foam simulations indicate that foam performance and surfactant transport are governed not only by constrained injection strategies, but also by a surfactant-partition coefficient. This novel CO2-soluble-surfactant concept diversifies injection strategies with respect to operational constraints, thus broadening the application of foam process. For a given injection strategy, a surfactant-partition coefficient could be optimized to improve injectivity and sweep efficiency. The optimal partition of the surfactant between the CO2 and aqueous phases minimizes the wasting of expensive surfactant in water that never comes in contact with CO2.

ACS Style

Guangwei Ren; Hang Zhang; Quoc P. Nguyen. Effect of Surfactant Partitioning on Mobility Control During CO2 Flooding. SPE Journal 2013, 18, 752 -765.

AMA Style

Guangwei Ren, Hang Zhang, Quoc P. Nguyen. Effect of Surfactant Partitioning on Mobility Control During CO2 Flooding. SPE Journal. 2013; 18 (4):752-765.

Chicago/Turabian Style

Guangwei Ren; Hang Zhang; Quoc P. Nguyen. 2013. "Effect of Surfactant Partitioning on Mobility Control During CO2 Flooding." SPE Journal 18, no. 4: 752-765.