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Chao Zhang
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266555, China

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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.

Journal article
Published: 26 October 2020 in Energy & Fuels
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ACS Style

Qichao Lv; Tongke Zhou; Rong Zheng; Xing Zhang; Zhaoxia Dong; Chao Zhang; Zhaomin Li. Aqueous CO2 Foam Armored by Particulate Matter from Flue Gas for Mobility Control in Porous Media. Energy & Fuels 2020, 34, 14464 -14475.

AMA Style

Qichao Lv, Tongke Zhou, Rong Zheng, Xing Zhang, Zhaoxia Dong, Chao Zhang, Zhaomin Li. Aqueous CO2 Foam Armored by Particulate Matter from Flue Gas for Mobility Control in Porous Media. Energy & Fuels. 2020; 34 (11):14464-14475.

Chicago/Turabian Style

Qichao Lv; Tongke Zhou; Rong Zheng; Xing Zhang; Zhaoxia Dong; Chao Zhang; Zhaomin Li. 2020. "Aqueous CO2 Foam Armored by Particulate Matter from Flue Gas for Mobility Control in Porous Media." Energy & Fuels 34, no. 11: 14464-14475.

Journal article
Published: 20 July 2020 in Fuel
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Due to its lower viscosity and thus better injectivity than water, CO2 injection has attracted lots of attention in tight oil recovery. Lowering the minimum miscible pressure (MMP) of CO2 and crude oil for an easier realization of the miscible condition where crude oil is displaced the most efficiently by CO2 is critical in CO2 injection. However, the limited solubilities of most surfactants in CO2 impose difficulties in reducing the MMP as surfactants can hardly in presence at the interface to lower the interfacial tension (IFT). In this work, we overcome this limitation by introducing ethanol as a co-solvent to notably promote the solubilities of four different surfactants (NP-9, 2EH-PO5-EO9, AOT, and TXIB) in CO2. As a consequence of the enhanced solubilities, the surfactants reduce more efficiently the CO2-crude oil IFT and MMP. Systematical measurements of CO2-crude oil IFT are conducted to distinguish the efficiencies of the four surfactants with and without ethanol as co-solvent. Based on the measured IFT, solubilities, and partition coefficients of the surfactants in CO2 and crude oil, a mechanistic understanding of the synergy between ethanol and surfactants are proposed. Under the optimal conditions of 7 wt% ethanol and 0.3 wt% TXIB, the MMP of crude oil and CO2 can be reduced as much as 30.2%. The remarkable reduction of MMP is very intriguing and will be highly beneficial in tight oil recovery.

ACS Style

Chao Zhang; Linghui Xi; Pingkeng Wu; Zhaomin Li. A novel system for reducing CO2-crude oil minimum miscibility pressure with CO2-soluble surfactants. Fuel 2020, 281, 118690 .

AMA Style

Chao Zhang, Linghui Xi, Pingkeng Wu, Zhaomin Li. A novel system for reducing CO2-crude oil minimum miscibility pressure with CO2-soluble surfactants. Fuel. 2020; 281 ():118690.

Chicago/Turabian Style

Chao Zhang; Linghui Xi; Pingkeng Wu; Zhaomin Li. 2020. "A novel system for reducing CO2-crude oil minimum miscibility pressure with CO2-soluble surfactants." Fuel 281, no. : 118690.

Journal article
Published: 08 February 2020 in Fuel
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CO2 foam has been widely scrutinized as a potential candidate in enhanced oil recovery while reducing CO2 emissions through geo-sequestration due to the high-efficiency CO2 mobility control ability. However, its application has been retarded partially because of the limited solubility of commercial and environmentally friendly surfactants in supercritical CO2. In this work, the challenge of limited solubility of surfactant sodium bis(2-ethylhexyl) sulfosuccinate (AOT) in CO2 is overcome by using ethanol as a co-solvent. The presented MD simulation reveals the underlying mechanism of the ethanol increased solubility of AOT in CO2 and the subsequently water-CO2 interfacial properties favorable for a stable CO2 foam. Experimental observation is in good accordance with the MD simulation that foamability and foam stability both significantly increase with ethanol as co-solvent, and their dependence on ethanol content. With ethanol as co-solvent to assist the dissolution of AOT in CO2, the CO2 foam has a high stiffness and the foam film has a high dilational modulus under high pressure of 15 MPa, which explain the stable CO2 foam. Experiments also show that ethanol helps the foam regeneration, making the practical oil field application of the presented system even more promising.

ACS Style

Chao Zhang; Pingkeng Wu; Zhaomin Li; Tao Liu; Ling Zhao; Dongdong Hu. Ethanol enhanced anionic surfactant solubility in CO2 and CO2 foam stability: MD simulation and experimental investigations. Fuel 2020, 267, 117162 .

AMA Style

Chao Zhang, Pingkeng Wu, Zhaomin Li, Tao Liu, Ling Zhao, Dongdong Hu. Ethanol enhanced anionic surfactant solubility in CO2 and CO2 foam stability: MD simulation and experimental investigations. Fuel. 2020; 267 ():117162.

Chicago/Turabian Style

Chao Zhang; Pingkeng Wu; Zhaomin Li; Tao Liu; Ling Zhao; Dongdong Hu. 2020. "Ethanol enhanced anionic surfactant solubility in CO2 and CO2 foam stability: MD simulation and experimental investigations." Fuel 267, no. : 117162.

Research article
Published: 20 December 2019 in Energy Science & Engineering
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This paper investigates the CO2/N2 injection process in tight oil reservoirs considering the confinement effect. To study the microscopic physical mechanisms, the confinement effect is characterized by properties shift and capillarity and introduced into the flash calculation to obtain the phase equilibrium of mixture fluids (tight oil/CO2/N2) in tight porous media. The results indicate that the injected nitrogen gas could effectively maintain the reservoir pressure, while it also weakens the effects of the CO2 injection recovery mechanisms, notably diffusivity and viscosity reduction. In addition, a dual‐pore tight oil reservoir model is set up to investigate the CO2/N2 injection with ultra‐low permeability and hydraulic fracturing. The basic CO2 injection parameters are optimized by the orthogonal method. Based on CO2 injection process, three injection schemes of CO2/N2 injection, which are mixed‐gas injection, CO2‐alternating‐N2 (CAN) injection, and N2‐alternating‐CO2 (NAC) injection, were investigated and a comparative analysis was made for the pressure distribution, CO2 mole fraction distribution, and cumulative oil production. Based on this analysis, the CAN injection process proved to be the best injection scheme. A parametric analysis further suggested that the nitrogen gas injection rate was the most important factor. Besides, the effect of gravity drainage, reservoir permeability, nature fractures, and permeability heterogeneity on the oil production of CAN injection process were also investigated in detail. The results show that tight oil reservoir with better vertical connectivity, poor fracture growth, and higher heterogeneity is more favorable for the CO2/N2 injection process.

ACS Style

Shouya Wu; Zhaomin Li; Zhuangzhuang Wang; Hemanta K. Sarma; Chao Zhang; Mingxuan Wu. Investigation of CO 2 /N 2 injection in tight oil reservoirs with confinement effect. Energy Science & Engineering 2019, 8, 1194 -1208.

AMA Style

Shouya Wu, Zhaomin Li, Zhuangzhuang Wang, Hemanta K. Sarma, Chao Zhang, Mingxuan Wu. Investigation of CO 2 /N 2 injection in tight oil reservoirs with confinement effect. Energy Science & Engineering. 2019; 8 (4):1194-1208.

Chicago/Turabian Style

Shouya Wu; Zhaomin Li; Zhuangzhuang Wang; Hemanta K. Sarma; Chao Zhang; Mingxuan Wu. 2019. "Investigation of CO 2 /N 2 injection in tight oil reservoirs with confinement effect." Energy Science & Engineering 8, no. 4: 1194-1208.

Research article
Published: 24 June 2019 in Energy Science & Engineering
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The properties of the foam fluid in porous media depend on its dynamic structure. However, few studies have focused on the dynamic structural change in foam. In this research, a method based on the level set method is proposed for the simulation of aqueous foam transport in porous media. As a first step, we focus on the Jamin effect, and a concise relation is established which reveals that the resultant pressure is proportional to the capillary pressure. Second, the snap‐off process of foam in porous media is studied, and both the two stages, including partial disintegration, are revealed based on the results. Third, the conclusion that foam automatically selects a larger channel in which to continue flowing is obtained by studying the foam selectivity. Finally, experiments are carried out to verify the simulation results using different models. The simulation results are in good agreement with the experimental results. These results are expected to be helpful for further understanding the foam characteristics and their effective applications.

ACS Style

Chao Zhang; Fei Wang; Zhaomin Li; Hailong Chen. Dynamic simulation and experimental verification of foam transport in porous media based on level set method. Energy Science & Engineering 2019, 7, 1795 -1807.

AMA Style

Chao Zhang, Fei Wang, Zhaomin Li, Hailong Chen. Dynamic simulation and experimental verification of foam transport in porous media based on level set method. Energy Science & Engineering. 2019; 7 (5):1795-1807.

Chicago/Turabian Style

Chao Zhang; Fei Wang; Zhaomin Li; Hailong Chen. 2019. "Dynamic simulation and experimental verification of foam transport in porous media based on level set method." Energy Science & Engineering 7, no. 5: 1795-1807.

Journal article
Published: 21 April 2019 in Colloids and Surfaces A: Physicochemical and Engineering Aspects
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The properties of foam fluid are substantially determined by its interfacial dynamics changes during foam transport. In this research, a foam flow simulation model based on the level set method and the N-S equation with surface tension term is established to simulate the dynamic interface evolution mechanism of group foam and individual foam from various aspects such as drainage process and foam migration in porous media, coalescence and Jamin effect. The results show that the foam life decreases linearly with the logarithm of the surface tension and enhances linearly with the liquid viscosity. For foam transport in porous media, both flowing foam and trapped foam exist, and the pressure fluctuates at a certain pressure value and the best foam structure is achieved at the optimum conditions with the optimum values of gas-liquid ratio, surface tension, and porosity being 1:1˜3:2, 0.1˜0.3, and 44.4%, respectively. Besides, the temporary blocking effect of foam has been verified. During the foam coalescence, foam gradually evolves towards minimum interfacial energy with oscillating and gradually decreasing foam volume. During the process of the foam passing through the throat, the maximum pressure occurs when the front end of the foam reaches the narrowest point, and the minimum pressure occurs when half of the foam passes through the narrowest point. The maximum pressure elevates linearly with the surface tension and the inverse of the throat radius.

ACS Style

Fei Wang; Dongxing Du; Hailong Chen; Chao Zhang. Simulation of evolution mechanism of dynamic interface of aqueous foam in narrow space base on level set method. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2019, 574, 1 -11.

AMA Style

Fei Wang, Dongxing Du, Hailong Chen, Chao Zhang. Simulation of evolution mechanism of dynamic interface of aqueous foam in narrow space base on level set method. Colloids and Surfaces A: Physicochemical and Engineering Aspects. 2019; 574 ():1-11.

Chicago/Turabian Style

Fei Wang; Dongxing Du; Hailong Chen; Chao Zhang. 2019. "Simulation of evolution mechanism of dynamic interface of aqueous foam in narrow space base on level set method." Colloids and Surfaces A: Physicochemical and Engineering Aspects 574, no. : 1-11.

Review article
Published: 29 December 2018 in Journal of Petroleum Science and Engineering
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Foam is considered as a promising candidate in petroleum industry for liquid unloading and improving gas mobility control during gas injection for Enhanced oil recovery (EOR) among other uses. However, reservoir heterogeneity such as rock mineralogy, water salinity and reservoir temperature limits surfactant selection, efficiency and application to create a stable foam. This research focuses on foam efficiency optimization when subjected to high salinity by designing experiments to investigate synergism and antagonism of foamer formulations containing different surfactants. Three different individual surfactants: anionic Sodium Dodecyl Sulfate (SDS), cationic Hexadecyltrimethylammonium Bromide (HDTAB) and nonionic (TX100), and binary mixed surfactants in ratios of 1:1, 1:2 and 2:1 were probed in both pure deionized water and in salt water. The critical micelle concentration (CMC) of each surfactant solution was obtained by measuring the surface tension as a function of the total concentration under standard conditions. Rubingh's theory was employed to determine the CMC of binary mixed surfactants. The synergism and antagonism in binary surfactants is well explained by the chemical nature of individual surfactants and their ability to lower the CMC. Experimental results indicate that anionic/nonionic and cationic/nonionic surfactants form a strong synergistic interaction minimizing the CMC up to 0.308 and 0.34 mM. A combination of anionic and cationic indicates antagonism. Therefore, synergistic mixed surfactant systems at proper ratios exhibit better foamability and stability than individual surfactants. Thus, they can be a proper tool to optimize foam efficiency appropriate for EOR and other applications in high salinity conditions.

ACS Style

Mhenga Agneta; Li Zhaomin; Zhang Chao; Gwamba Gerald. Investigating synergism and antagonism of binary mixed surfactants for foam efficiency optimization in high salinity. Journal of Petroleum Science and Engineering 2018, 175, 489 -494.

AMA Style

Mhenga Agneta, Li Zhaomin, Zhang Chao, Gwamba Gerald. Investigating synergism and antagonism of binary mixed surfactants for foam efficiency optimization in high salinity. Journal of Petroleum Science and Engineering. 2018; 175 ():489-494.

Chicago/Turabian Style

Mhenga Agneta; Li Zhaomin; Zhang Chao; Gwamba Gerald. 2018. "Investigating synergism and antagonism of binary mixed surfactants for foam efficiency optimization in high salinity." Journal of Petroleum Science and Engineering 175, no. : 489-494.

Research article
Published: 07 August 2018 in SIMULATION
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To satisfy the requirements of the new technology of carbon capture, utilization, and storage (CCUS), it is recommended that carbon dioxide-enhanced oil recovery (CO2-EOR) projects change their design objective index by taking carbon sequestration into account, an approach that significantly differs from the traditional design. This study builds a new optimal index function for the new requirement based on the existing indices of the traditional index and the Kovscek index, which are inapplicable for co-optimization. The proposed approach improves the existing methods in terms of the weight function and representation parameters, making the method more suitable for the optimization and evaluation of the carbon sequestration and enhanced oil recovery process. This objective index can be used to obtain the optimization time point. To validate the proposed approach, a CO2-EOR simulation process has been evaluated using the proposed index, and the optimization time point obtained (the 6054th day, f = 1.001). The optimized process would have a better development effect on CO2-EOR by comparison of simulation results. Then, this optimal index was applied on a CO2-EOR project in Wasson oil field. The results suggest that the injection measures should be introduced at the 13th and 17th years, and this improved objective index can be effectively applied to the carbon sequestration and enhanced oil recovery process.

ACS Style

Chao Zhang; Shouya Wu; Zhaomin Li; Dongya Zhao; Guangzhong Lv. Improved co-optimal and evaluable index of carbon sequestration and enhanced oil recovery. SIMULATION 2018, 97, 145 -154.

AMA Style

Chao Zhang, Shouya Wu, Zhaomin Li, Dongya Zhao, Guangzhong Lv. Improved co-optimal and evaluable index of carbon sequestration and enhanced oil recovery. SIMULATION. 2018; 97 (2):145-154.

Chicago/Turabian Style

Chao Zhang; Shouya Wu; Zhaomin Li; Dongya Zhao; Guangzhong Lv. 2018. "Improved co-optimal and evaluable index of carbon sequestration and enhanced oil recovery." SIMULATION 97, no. 2: 145-154.

Journal article
Published: 08 June 2018 in Energies
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In this paper, a generalized methodology has been developed to determine the diffusion coefficient of supercritical CO2 in cores that are saturated with different oil samples, under reservoir conditions. In theory, a mathematical model that combines Fick’s diffusion equation and the Peng-Robinson equation of state has been established to describe the mass transfer process. In experiments, the pressure decay method has been employed, and the CO2 diffusion coefficient can be determined once the experimental data match the computational result of the theoretical model. Six oil samples with different compositions (oil samples A to F) are introduced in this study, and the results show that the supercritical CO2 diffusion coefficient decreases gradually from oil samples A to F. The changing properties of oil can account for the decrease in the CO2 diffusion coefficient in two aspects. First, the increasing viscosity of oil slows down the speed of the mass transfer process. Second, the increase in the proportion of heavy components in oil enlarges the mass transfer resistance. According to the results of this work, a lower viscosity and lighter components of oil can facilitate the mass transfer process.

ACS Style

Chao Zhang; Chenyu Qiao; Songyan Li; Zhaomin Li. The Effect of Oil Properties on the Supercritical CO2 Diffusion Coefficient under Tight Reservoir Conditions. Energies 2018, 11, 1495 .

AMA Style

Chao Zhang, Chenyu Qiao, Songyan Li, Zhaomin Li. The Effect of Oil Properties on the Supercritical CO2 Diffusion Coefficient under Tight Reservoir Conditions. Energies. 2018; 11 (6):1495.

Chicago/Turabian Style

Chao Zhang; Chenyu Qiao; Songyan Li; Zhaomin Li. 2018. "The Effect of Oil Properties on the Supercritical CO2 Diffusion Coefficient under Tight Reservoir Conditions." Energies 11, no. 6: 1495.

Research article
Published: 17 April 2018 in Energy & Fuels
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The utilization of conventional water-soluble surfactants for the stabilization of CO2 foams has been limited by the low injectability of low-permeability reservoirs. In this study, the anionic surfactant sodium bis(2-ethylhexyl) sulfosuccinate (AOT) was used as the CO2-soluble surfactant to stabilize CO2 foams in the presence of ethanol. The phase equilibrium relationships of the AOT/ethanol/CO2 system and the partition coefficient of AOT between supercritical CO2 (SC-CO2) and water were measured through a fully visible PVT cell. In addition, the effects of the ethanol content on the partition coefficient and interfacial tension (IFT) were studied. Furthermore, a laboratory apparatus was developed to measure the viscosity and injection performance of AOT dissolved in an aqueous or SC-CO2 solution and SC-CO2 foams. The experimental data show that addition of ethanol can significantly improve the solubility of AOT in SC-CO2 and increase the partition coefficient of AOT. The IFT tests show that the ethanol content affects the critical micelle concentration (cmc) and IFT at cmc (γcmc) differently: with ethanol addition, γcmc decreases, while the cmc first decreases and then increases. The dissolution of AOT in SC-CO2 with ethanol could lead to a threefold increase for SC-CO2 viscosity, while the formation of SC-CO2 foam could result in an increase for viscosity of approximately 50~200 times. Finally, the core flooding results show that dissolved AOT in SC-CO2 could significantly improve the surfactant injectivity in tight rocks and interact with the formation water in situ to form SC-CO2 foams, controlling the mobility of the CO2. In addition, the performance of SC-CO2 foams could be governed by altering the ethanol content to adjust the surfactant partition coefficient.

ACS Style

Chao Zhang; Zhaomin Li; Songyan Li; Qichao Lv; Peng Wang; Jiquan Liu; Jianlin Liu. Enhancing Sodium Bis(2-ethylhexyl) Sulfosuccinate Injectivity for CO2 Foam Formation in Low-Permeability Cores: Dissolving in CO2 with Ethanol. Energy & Fuels 2018, 32, 5846 -5856.

AMA Style

Chao Zhang, Zhaomin Li, Songyan Li, Qichao Lv, Peng Wang, Jiquan Liu, Jianlin Liu. Enhancing Sodium Bis(2-ethylhexyl) Sulfosuccinate Injectivity for CO2 Foam Formation in Low-Permeability Cores: Dissolving in CO2 with Ethanol. Energy & Fuels. 2018; 32 (5):5846-5856.

Chicago/Turabian Style

Chao Zhang; Zhaomin Li; Songyan Li; Qichao Lv; Peng Wang; Jiquan Liu; Jianlin Liu. 2018. "Enhancing Sodium Bis(2-ethylhexyl) Sulfosuccinate Injectivity for CO2 Foam Formation in Low-Permeability Cores: Dissolving in CO2 with Ethanol." Energy & Fuels 32, no. 5: 5846-5856.