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Songyan Li
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266555, China

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Journal article
Published: 30 July 2021 in Journal of Petroleum Science and Engineering
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Carbon dioxide miscible flooding has been proven to be one of the most effective enhanced oil recovery (EOR) technologies, particularly for light and medium oil reservoirs. However, specific effects of pore structure on CO2 miscible flooding recovery in low permeability reservoir lack in-depth understandings. In this paper, pore structures are specifically studied by means of the molecular mechanics to evaluate their effects on the CO2 EOR in the low permeability reservoir. First, a series lab experiments are performed for the pore and fluid characterization. More specifically, the pore throat size and distribution frequency are measured from the high-pressure mercury injection and nuclear magnetic resonance. The minimum miscibility pressure is determined from the slim-tube tests with known oil compositions tested from gas chromatography analysis. Second, the regularity of CO2 extraction is explored on the basis of molecular mechanics and the thickness of raffinate is calculated. Finally, the raffinate volume and recovery ratio in the pores are calculated after the CO2 miscible flooding. The results show that a raffinate-layer with thickness of 0.13 μm remains on the surface of the pore after the CO2 miscible flooding, which would cause the oil to be immobile since the throat could be blocked when the throat radius is smaller than 0.26 μm. The recoveries of cores C-1 and C-2 are 70.1 % and 61.4 % from calculations and 68.4 % and 59.8 % from experiments, whose errors are 2.5 % and 2.7 %, respectively. This study would be beneficial to analyze the CO2 miscible flooding in reservoirs with different pore structures and provide technical support for improving CO2 utilization efficiency.

ACS Style

Hengli Wang; Leng Tian; Xiaolong Chai; Jiaxin Wang; Kaiqiang Zhang. Effect of pore structure on recovery of CO2 miscible flooding efficiency in low permeability reservoirs. Journal of Petroleum Science and Engineering 2021, 208, 109305 .

AMA Style

Hengli Wang, Leng Tian, Xiaolong Chai, Jiaxin Wang, Kaiqiang Zhang. Effect of pore structure on recovery of CO2 miscible flooding efficiency in low permeability reservoirs. Journal of Petroleum Science and Engineering. 2021; 208 ():109305.

Chicago/Turabian Style

Hengli Wang; Leng Tian; Xiaolong Chai; Jiaxin Wang; Kaiqiang Zhang. 2021. "Effect of pore structure on recovery of CO2 miscible flooding efficiency in low permeability reservoirs." Journal of Petroleum Science and Engineering 208, no. : 109305.

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: 04 February 2021 in Journal of Petroleum Science and Engineering
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Although various thermal technologies have been used in its oil recovery, including SAGD, there have been few studies on systematical analyzing the cracking behaviors of Mackay River oil sand. In the present work, a series of thermal cracking and aquathermolysis reactions have been carried out at different temperatures for different times. The viscosity, API°, SARA contents, elemental contents, and average relative molecular weights of cracked oil samples, as well as the gas product compositions have been analyzed to characterize the reaction performance of oil sand. The results showed that the aquathermolysis was superior to thermal cracking on the viscosity reduction and quality upgrading of the oil sand, and the thermal cracking of oil sand took place at 250 °C, while the cracking reactions took place at 200 °C in aquathermolysis. The viscosity reduction and API° enhancements depended on the changes of the oil sand molecular structures and its components. Besides, we have obtained fitted equations of the viscosity reduction ratio to the reaction temperature, by which the viscosity reduction effects of the oil sand could be predicted. Moreover, the gas compositions can be used to monitor the cracking performance of the oil sand in thermal cracking and aquathermolysis.

ACS Style

Xiao Qu; Yang Li; Songyan Li; Jiqian Wang; Hai Xu; Zhaomin Li. Thermal cracking, aquathermolysis, and their upgrading effects of Mackay River oil sand. Journal of Petroleum Science and Engineering 2021, 201, 108473 .

AMA Style

Xiao Qu, Yang Li, Songyan Li, Jiqian Wang, Hai Xu, Zhaomin Li. Thermal cracking, aquathermolysis, and their upgrading effects of Mackay River oil sand. Journal of Petroleum Science and Engineering. 2021; 201 ():108473.

Chicago/Turabian Style

Xiao Qu; Yang Li; Songyan Li; Jiqian Wang; Hai Xu; Zhaomin Li. 2021. "Thermal cracking, aquathermolysis, and their upgrading effects of Mackay River oil sand." Journal of Petroleum Science and Engineering 201, no. : 108473.

Journal article
Published: 07 January 2021 in Chemical Engineering Journal
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Greenhouse gas mitigation and utilization attract huge attentions in energy and environment domains worldwide while few technologies enable to satisfy the both concurrently. In this study, a new greenhouse gas utilization technology, foamy emulsions, is initially developed and evaluated. Foamy emulsions usually have low production gas–liquid ratio but capable to facilitate the energy recovery. However, little researches have focused on the formation mechanism and flow property of foamy emulsions under greenhouse gas injection and the use of additives, which results in the relevant mechanism remains unclear. To address this problem, the formation process of foamy emulsions and the influence of the gas type, temperature and amount of viscosity reducer on the flow of foamy emulsions in the process of unconventional fossil fluids are investigated through a series of microscopic visualization experiments. According to the experimental results, the process of foamy emulsions formation can be divided into four stages, namely, the initial, early, middle and late stages. The middle stage corresponds to the period of steady flow of the foamy oil, with the largest number of bubbles and highest velocity. Moreover, the foamy emulsions formed using CO2 as the dissolved gas is the most effective, corresponding to an energy recovery factor of 40%. The effect of N2 is the most inferior, with the corresponding oil recovery factor being only 18%. Although the velocity of the bubbles increases with the increase in the temperature and amount of viscosity reducer, the stability of the bubbles degrades. The optimal effect of the foamy emulsions occurs at 80 °C with the amount of viscosity reducer being 1–3 wt%. This study will support the foundation of more general application pertaining to greenhouse gases mitigation and utilization in energy and environmental practices.

ACS Style

Songyan Li; Zhiheng Hu; Chen Lu; Mingxuan Wu; Kaiqiang Zhang; Weilin Zheng. Microscopic visualization of greenhouse-gases induced foamy emulsions in recovering unconventional petroleum fluids with viscosity additives. Chemical Engineering Journal 2021, 411, 128411 .

AMA Style

Songyan Li, Zhiheng Hu, Chen Lu, Mingxuan Wu, Kaiqiang Zhang, Weilin Zheng. Microscopic visualization of greenhouse-gases induced foamy emulsions in recovering unconventional petroleum fluids with viscosity additives. Chemical Engineering Journal. 2021; 411 ():128411.

Chicago/Turabian Style

Songyan Li; Zhiheng Hu; Chen Lu; Mingxuan Wu; Kaiqiang Zhang; Weilin Zheng. 2021. "Microscopic visualization of greenhouse-gases induced foamy emulsions in recovering unconventional petroleum fluids with viscosity additives." Chemical Engineering Journal 411, no. : 128411.

Journal article
Published: 13 November 2020 in Fuel
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Stability of carbon dioxide foam attracts huge attentions while being of great challenge to many industrial practices. In this paper, aqueous CO2 foam stabilized with synergy of hydrophilic nanoparticles and nonionic surfactants was experimentally investigated at elevated temperatures and extreme salinities. The foam formula consisting of 1.5 wt% T40 and 2.49 mM C12E23 was determined under elevated temperature and salinity conditions. At 80 °C, the foam volume of the C12E23/T40 foam is 225 mL, and the half-life is 32 min, which is 13.9 times that of the C12E23 foam. At a salinity of 17 × 104 mg/L, the foam volume is 185 mL, and the half-life is 71 min, which is 24.4 times that of the C12E23 foam. With increasing salinity and temperature, the interfacial tension rises, and the viscoelastic modulus gradually declines, resulting in a lower foam stability. However, the T40/C12E23 foam has a good temperature and salinity tolerance, which can be used under harsh reservoir conditions. In a heterogeneous microscopic visualization model, water channeling in high-permeability regions inhibits the further increase in oil recovery. Subsequent injection of the C12E23/T40 foam improves the oil recovery factor up to 86.2%. The C12E23/T40 foam enhances the oil recovery by increasing the sweep area and flooding efficiency. In a sandpack model, the plugging pressure gradient of the CO2 foam stabilized by 2.49 mM C12E23 and 1.5 wt% T40 reaches 25.3 MPa/m, which is 12.65 times higher than that of the C12E23 foam. The composite reinforced foam attains good water blocking and profile control effects, thereby increasing the oil recovery factor 20.1% after water flooding. This study of great importance to improve not only the oil recovery efficiency, also anywhere where CO2-in brine foam applicable.

ACS Style

Kang Yang; Songyan Li; Kaiqiang Zhang; Yongwei Wang. Synergy of hydrophilic nanoparticle and nonionic surfactant on stabilization of carbon dioxide-in-brine foams at elevated temperatures and extreme salinities. Fuel 2020, 288, 119624 .

AMA Style

Kang Yang, Songyan Li, Kaiqiang Zhang, Yongwei Wang. Synergy of hydrophilic nanoparticle and nonionic surfactant on stabilization of carbon dioxide-in-brine foams at elevated temperatures and extreme salinities. Fuel. 2020; 288 ():119624.

Chicago/Turabian Style

Kang Yang; Songyan Li; Kaiqiang Zhang; Yongwei Wang. 2020. "Synergy of hydrophilic nanoparticle and nonionic surfactant on stabilization of carbon dioxide-in-brine foams at elevated temperatures and extreme salinities." Fuel 288, no. : 119624.

Journal article
Published: 06 November 2020 in Chemical Engineering Science
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In the lifting process of drainage gas recovery, external conditions and internal components of the foam are complex. We used molecular dynamics simulation to construct a series of fatty alcohol polyoxyethylene ether sulfate (AES) foam models that could represent various foams in different lifting stages from well to ground. The effect of temperature and pressure on foam stability was investigated. We found that there are two main reasons for foam instability in the first-half stage of the lifting process. Firstly, high temperature aggravated the molecule movement; some CH4 molecules entered the foam film and formed a molecular transport channel. Secondly, the interaction between the CH4 phase and condensate oil leads to some alkane molecules entering the gas-liquid interface. The calculation results and theoretical analysis will help to deepen the understanding of the performance of oily foams under harsh conditions.

ACS Style

Hongbing Wang; Ji Liu; Qi Yang; Yan Wang; Songyan Li; Shuangqing Sun; Songqing Hu. Study on the influence of the external conditions and internal components on foam performance in gas recovery. Chemical Engineering Science 2020, 231, 116279 .

AMA Style

Hongbing Wang, Ji Liu, Qi Yang, Yan Wang, Songyan Li, Shuangqing Sun, Songqing Hu. Study on the influence of the external conditions and internal components on foam performance in gas recovery. Chemical Engineering Science. 2020; 231 ():116279.

Chicago/Turabian Style

Hongbing Wang; Ji Liu; Qi Yang; Yan Wang; Songyan Li; Shuangqing Sun; Songqing Hu. 2020. "Study on the influence of the external conditions and internal components on foam performance in gas recovery." Chemical Engineering Science 231, no. : 116279.

Journal article
Published: 30 October 2020 in International Journal of Heat and Mass Transfer
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Complex foam flows in series and parallel are investigated by means of a self-designed high-pressure high-temperature laboratory physical model. A total of twenty-two foam flow experiments were conducted in the porous media with a wide permeability range over two orders of magnitude. Specifically, fifteen single and seven dual foam flows in porous media with respective permeability range of 37−9705 mD and 41−7838 mD were performed to determine a series of physiochemical properties in terms of foam rheology, fluid profile and mobility control. For the foam flows in series, the overall gas saturation with process of foam injection is found to quickly increase within initial period but then tend to be stable. At the end of foam injection, the gas saturation curve could be clearly distinguished with permeability variances that a sharp rising range for permeability from 37 to 1233 mD while a quasi-stable range from 1233 to 9705 mD. Mobility reduction factor and apparent viscosity of the single flow cases are found to increase initially but in subsequent a decline with the permeability increase, whose maximum values were equal to 726.34 and 646.44 mPa•s at the permeability of 4386 mD. Moreover, the mobility curve basically performs as a U shape with three distinct periods: a sharp initial decrease period from 37 to 564 mD in subsequent of a second uniform mobility from 564 to 7309 and third increase period from 7309 to 9705 mD. On the other hand, for the foam flow in parallel, the profile control effect is determined to be favorable for a medium permeability ranging from 282 to 3855 mD but unfavorable for either lower- or higher-permeability cases. In the post-foam water injection period, the gas saturation for the single flow case monotonically decreases while for the flow in parallel, the gas and liquid production profiles perform oppositely to the profile control effect with respect to the permeability. Overall, gas and liquid mobilities are proven to be simultaneously controlled for foam flows in series and parallel through multiscale porous media, whereas a gas mobility is better controlled, particularly in porous media with lower permeability.

ACS Style

Songyan Li; Peng Wu; Kaiqiang Zhang. Complex foam flow in series and parallel through multiscale porous media: Physical model interpretation. International Journal of Heat and Mass Transfer 2020, 164, 120628 .

AMA Style

Songyan Li, Peng Wu, Kaiqiang Zhang. Complex foam flow in series and parallel through multiscale porous media: Physical model interpretation. International Journal of Heat and Mass Transfer. 2020; 164 ():120628.

Chicago/Turabian Style

Songyan Li; Peng Wu; Kaiqiang Zhang. 2020. "Complex foam flow in series and parallel through multiscale porous media: Physical model interpretation." International Journal of Heat and Mass Transfer 164, no. : 120628.

Journal article
Published: 21 September 2020 in Journal of CO2 Utilization
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In this paper, extraheavy oil recovery assisted by CO2 and an oil-soluble viscosity reducer under deep reservoir conditions was experimentally investigated. Specifically, the viscosity reduction efficiency of the oil-soluble viscosity reducer was measured, and the morphological characteristics of the asphaltenes in the heavy oil were observed by scanning electron microscopy (SEM) and atomic force microscopy (AFM). CO2 huff-n-puff experiments were carried out to determine the oil recovery factor and the oil/gas exchange ratio. The properties of the produced oil were tested, and the oil saturation in cores was scanned through nuclear magnetic resonance (NMR). The experimental results show that the oil-soluble viscosity reducer decreases the viscosity of extraheavy oil by decreasing the asphaltene concentration and the size of the asphaltene aggregations in the extraheavy oil. CO2 huff-n-puff assisted by an oil-soluble viscosity reducer can considerably improve the oil recovery of extraheavy oil. When the concentration of the viscosity reducer increases from 0 to 10 wt%, the oil recovery factor after five cycles increases from 18.74 % to 34.44 %, and the foamy oil effect is stimulated. An economic concentration range of 1–3 wt% is suggested for field CO2 huff-n-puff applications. With increasing CO2 huff-n-puff cycles, the cyclic oil recovery factor and oil/gas exchange ratio sharply decrease. The oil recovery and oil/gas exchange ratio of the first two cycles are considerably higher than those of the last three cycles. The oil saturation tested by NMR shows that the sweep area of CO2 huff-n-puff is limited to the first two-thirds of the core, indicating that the injection volume of CO2 should be increased with each successive cycle, and the well distance should be suitably decreased to improve the oil recovery of the whole reservoir.

ACS Style

Songyan Li; Chen Lu; Mingxuan Wu; Zhiheng Hu; Zhaomin Li; Zhiyuan Wang. New insight into CO2 huff-n-puff process for extraheavy oil recovery via viscosity reducer agents: An experimental study. Journal of CO2 Utilization 2020, 42, 101312 .

AMA Style

Songyan Li, Chen Lu, Mingxuan Wu, Zhiheng Hu, Zhaomin Li, Zhiyuan Wang. New insight into CO2 huff-n-puff process for extraheavy oil recovery via viscosity reducer agents: An experimental study. Journal of CO2 Utilization. 2020; 42 ():101312.

Chicago/Turabian Style

Songyan Li; Chen Lu; Mingxuan Wu; Zhiheng Hu; Zhaomin Li; Zhiyuan Wang. 2020. "New insight into CO2 huff-n-puff process for extraheavy oil recovery via viscosity reducer agents: An experimental study." Journal of CO2 Utilization 42, no. : 101312.

Research letter
Published: 31 July 2020 in Geophysical Research Letters
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Understanding nanoconfined water effect on CO2 utilization and storage has tremendous implications in academic research and practical applications, especially for extremely low‐permeability shale reservoirs. Here, a new nanoscale‐extended cubic‐plus association equation of state is developed by including the confinement effects and intermolecular interactions, based on which the phase behavior and interfacial tension of the pure water and water–CO2 system are accurately calculated. Moreover, three important parameters, caprock sealing pressure, maximum storage height, and storage capacity, are quantitatively determined for assessing the potential for the CO2 storage. On the basis of the results from this study, the negative effect of nanoconfiend water can be substantially reduced or even converted to be positive for the CO2 utilization and storage in the shale reservoirs due to the extremely small pore scale as well as the associated strong confinements and intermolecular interactions. Overall, this study supports the foundation of general practical applications pertaining to CO2 utilization and geological storage in unconventional low‐permeability shale formations with existence of nanoconfined water.

ACS Style

Kaiqiang Zhang; Lirong Liu; Guohe Huang. Nanoconfined Water Effect on CO 2 Utilization and Geological Storage. Geophysical Research Letters 2020, 47, 1 .

AMA Style

Kaiqiang Zhang, Lirong Liu, Guohe Huang. Nanoconfined Water Effect on CO 2 Utilization and Geological Storage. Geophysical Research Letters. 2020; 47 (15):1.

Chicago/Turabian Style

Kaiqiang Zhang; Lirong Liu; Guohe Huang. 2020. "Nanoconfined Water Effect on CO 2 Utilization and Geological Storage." Geophysical Research Letters 47, no. 15: 1.

Review
Published: 03 June 2020 in Petroleum Science
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Carbonate reservoirs worldwide are complex in structure, diverse in form, and highly heterogeneous. Based on these characteristics, the reservoir stimulation technologies and fluid flow characteristics of carbonate reservoirs are briefly described in this study. The development methods and EOR technologies of carbonate reservoirs are systematically summarized, the relevant mechanisms are analyzed, and the application status of oil fields is catalogued. The challenges in the development of carbonate reservoirs are discussed, and future research directions are explored. In the current development processes of carbonate reservoirs, water flooding and gas flooding remain the primary means but are often prone to channeling problems. Chemical flooding is an effective method of tertiary oil recovery, but the harsh formation conditions require high-performance chemical agents. The application of emerging technologies can enhance the oil recovery efficiency and environmental friendliness to a certain extent, which is welcome in hard-to-recover areas such as heavy oil reservoirs, but the economic cost is often high. In future research on EOR technologies, flow field control and flow channel plugging will be the potential directions of traditional development methods, and the application of nanoparticles will revolutionize the chemical EOR methods. On the basis of diversified reservoir stimulation, combined with a variety of modern data processing schemes, multichannel EOR technologies are being developed to realize the systematic, intelligent, and cost-effective development of carbonate reservoirs.

ACS Style

Zheng-Xiao Xu; Song-Yan Li; Bin-Fei Li; Dan-Qi Chen; Zhong-Yun Liu; Zhao-Min Li. A review of development methods and EOR technologies for carbonate reservoirs. Petroleum Science 2020, 17, 990 -1013.

AMA Style

Zheng-Xiao Xu, Song-Yan Li, Bin-Fei Li, Dan-Qi Chen, Zhong-Yun Liu, Zhao-Min Li. A review of development methods and EOR technologies for carbonate reservoirs. Petroleum Science. 2020; 17 (4):990-1013.

Chicago/Turabian Style

Zheng-Xiao Xu; Song-Yan Li; Bin-Fei Li; Dan-Qi Chen; Zhong-Yun Liu; Zhao-Min Li. 2020. "A review of development methods and EOR technologies for carbonate reservoirs." Petroleum Science 17, no. 4: 990-1013.

Research article
Published: 06 May 2020 in Industrial & Engineering Chemistry Research
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In this paper, quantitative thermodynamic parameters are quantified and applied to evaluate the oilgas miscibility developments and determine the minimum miscibility pressures (MMPs) from bulk to nanometer scale. First, mathematical formulations of the Gibbs and interfacial energy and solubility parameter in bulk phase and nanopores are derived coupled with a modified equation of state and semi-analytical correlation. Second, the calculated Gibbs and interfacial energy and solubility parameter are utilized to analyze the miscibility development, based on which specific thermodynamic MMP criteria are developed. The calculated MMPs from the new thermodynamic MMP criteria are compared with and validated by the measured MMPs of a total of 55 dead and live oilpure and impure gas systems in bulk phase and nanopores at different conditions. Moreover, the effects of temperature, oil and gas composition and pore radius on the MMP are evaluated. It is found that the miscibility interpretation may be in variation based on different thermodynamic properties even though the miscible state performs similar in the macroscopic perspective. Three new thermodynamic MMP criteria are developed based on the first derivatives of the Gibbs energy and solubility parameter and second derivative of the interfacial energy with respect to pressure, which are linearly regressed and extrapolated to determine the MMP with a critical linear correlation coefficient. The three thermodynamic criteria are found to be accurate and physically correct for the MMP determinations of various oilgas systems in bulk phase and nanopores at different conditions, wherein the solubility parameter and interfacial energy criteria are slightly better than the Gibbs energy criterion. Overall, the miscibility is strongly dependent on the temperature, oil and gas compositions and pore radius.

ACS Style

Kaiqiang Zhang; Lirong Liu; Songyan Li; Na Jia. Thermodynamic Parameters for Quantitative Miscibility Interpretations from the Bulk to Nanometer Scale. Industrial & Engineering Chemistry Research 2020, 59, 10634 -10650.

AMA Style

Kaiqiang Zhang, Lirong Liu, Songyan Li, Na Jia. Thermodynamic Parameters for Quantitative Miscibility Interpretations from the Bulk to Nanometer Scale. Industrial & Engineering Chemistry Research. 2020; 59 (22):10634-10650.

Chicago/Turabian Style

Kaiqiang Zhang; Lirong Liu; Songyan Li; Na Jia. 2020. "Thermodynamic Parameters for Quantitative Miscibility Interpretations from the Bulk to Nanometer Scale." Industrial & Engineering Chemistry Research 59, no. 22: 10634-10650.

Journal article
Published: 04 May 2020 in Geothermics
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In this paper, a novel mathematical model for the heat extraction process from hot dry rocks (HDRs) by enclosed water recycling in a horizontal well is established, on a basis of which a series of exergy analyses are conducted. The pressure and temperature distributions in the wellbore and the exergy extracted under different working conditions are calculated. Eight factors are specifically studied to evaluate their effects on the accumulated exergy of the produced hot water. It is found that the accumulated exergy first gradually increases but decreases subsequently with the water rising flow rate. The accumulated exergy is noticed to increase obviously with the increase of the length for the horizontal section, temperature of the HDR, thermal conductivity of the HDR, and diameter of the casing. The temperature distributions in the HDR around the wellbore are analyzed at different time. More specifically, the temperature drop of the HDR gradually spreads to far area of the wellbore with the continuous extraction of geothermal energy. The temperature of the rock around the wellbore decreases by increasing the injection rate. A higher HDR thermal conductivity leads to a quick heat transfer from the remote to near wellbore area. The exergy analyses in this study provide strong theoretical supports to utilize the HDR heat extraction.

ACS Style

Songyan Li; Yifan Wang; Kaiqiang Zhang. Exergy analysis of heat extraction from hot dry rock by enclosed Water recycling in a horizontal Well. Geothermics 2020, 86, 101867 .

AMA Style

Songyan Li, Yifan Wang, Kaiqiang Zhang. Exergy analysis of heat extraction from hot dry rock by enclosed Water recycling in a horizontal Well. Geothermics. 2020; 86 ():101867.

Chicago/Turabian Style

Songyan Li; Yifan Wang; Kaiqiang Zhang. 2020. "Exergy analysis of heat extraction from hot dry rock by enclosed Water recycling in a horizontal Well." Geothermics 86, no. : 101867.

Thermodynamics and molecular scale phenomena
Published: 26 March 2020 in AIChE Journal
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Soluble and miscible states are two important thermodynamic states in academic research and practical applications but their quantitative distinctions are still fuzzy. In this study, for the first time, the mathematical formulations of the quantitative criteria for distinguishing the thermodynamic soluble and miscible states are analytically developed by means of the Flory‐Huggins solution theory and solubility parameter. The quantitative bottom and upper solubility limits for a total of thirteen binary and ternary mixtures are calculated at different conditions. Moreover, the composition, temperature and pore radius are specifically studied to evaluate their effects on the soluble and miscible states. On the basis of the work from this study, the insoluble, soluble but immiscible, and miscible states are definitively quantified and clearly distinguished for the first time. This article is protected by copyright. All rights reserved.

ACS Style

Kaiqiang Zhang; Na Jia; Lirong Liu. Quantitative distinction of thermodynamic soluble and miscible states. AIChE Journal 2020, 66, 1 .

AMA Style

Kaiqiang Zhang, Na Jia, Lirong Liu. Quantitative distinction of thermodynamic soluble and miscible states. AIChE Journal. 2020; 66 (6):1.

Chicago/Turabian Style

Kaiqiang Zhang; Na Jia; Lirong Liu. 2020. "Quantitative distinction of thermodynamic soluble and miscible states." AIChE Journal 66, no. 6: 1.

Journal article
Published: 09 February 2020 in Fuel
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In this paper, foam-assisted CO2 EOR and anti-gas channelling technology are investigated and optimized to enhance tight oil recovery. A series of laboratory experiments, including pressure−volume−temperature, foam generation and evaluation, and coreflood tests, and phase behaviour theoretical mathematical models are performed to evaluate foam agent, analyze anti-gas channelling mechanisms and influential factors, and optimize foam-assisted CO2 EOR technique. The specific CO2 bulk fluid behaviour and phase behaviour in wellbore are determined through experimental and theoretical models. Two distinct stages are found to be divided prior to and after the CO2 gas breakthrough. Most oil productions, which is in the range of 28–40%, occur prior to the gas breakthrough, whereas only additional 5–8% oil is produced after the gas breakthrough. A higher injection rate and/or permeability ratio result in an earlier gas breakthrough and causes less oil to be produced before gas breakthrough while the oil recovery factor slightly increases after the breakthrough by increasing injection rate. Gas diffusion in water-saturated core reach equilibrium faster than that in the oil-saturated core. An overall evaluation parameter is developed to select foam agent. The optimized static condition for the selected foam agent here is approximately 9 MPa at low temperatures while dynamic performance is improved at a higher gas but lower liquid injection rate. The simultaneous water-alternating-gas injection scheme in subsequent of an initial gas injection with liquid−gas ratio of 1:1 performs better than the water-alternating-gas scheme, which is proven to be effective for the core samples with fracture width of 82.67 μm. Finally, the oilfield surface foaming operational system is designed to upscale laboratory research to practical applications with specific operating setup and procedures, which has been applied in the target oil reservoir and performs well as expected.

ACS Style

Kaiqiang Zhang; Songyan Li; Lirong Liu. Optimized foam-assisted CO2 enhanced oil recovery technology in tight oil reservoirs. Fuel 2020, 267, 117099 .

AMA Style

Kaiqiang Zhang, Songyan Li, Lirong Liu. Optimized foam-assisted CO2 enhanced oil recovery technology in tight oil reservoirs. Fuel. 2020; 267 ():117099.

Chicago/Turabian Style

Kaiqiang Zhang; Songyan Li; Lirong Liu. 2020. "Optimized foam-assisted CO2 enhanced oil recovery technology in tight oil reservoirs." Fuel 267, no. : 117099.

Journal article
Published: 23 November 2019 in Fuel
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CO2 flooding is an important method in CO2 enhanced oil recovery (EOR) but is usually accompanied by a low efficiency for the fractured low-permeability formation due to CO2 low viscosity and high mobility. In this paper, a comprehensive experimental research effort including flooding and NMR testing is conducted to investigate the oil recovery and mobility control effects of a novel CO2 oil-based foam in fractured low-permeability cores. First, the foaming performance of the compound surfactant SF in crude oil that consists of Span20 and fluorochemical surfactant F-1 is evaluated by the blender stirring method. The surfactant SF exhibits a good foaming performance in crude oil with a foam volume of 290 mL and a half-life of 352 s. The bubble film is notably thickened, which results in a stable oil-based foam. Second, CO2 flooding and CO2 oil-based foam flooding in nonfractured and fractured cores are conducted under reservoir conditions. CO2 oil-based foam flooding can significantly improve the oil recovery and increase the sweep volume of injected CO2. Consequently, the oil recovery in fractured cores increases by 47.8%, and that in nonfractured cores increases by 39.1%. Third, the residual oil saturation in the cores is tested by NMR. The residual oil saturation of fractured and nonfractured cores after CO2 oil-based foam flooding is low and distributed evenly, indicating that CO2 oil-based foam reduces CO2 mobility and yields a relatively uniform displacement throughout the core.

ACS Style

Songyan Li; Qun Wang; Kaiqiang Zhang; Zhaomin Li. Monitoring of CO2 and CO2 oil-based foam flooding processes in fractured low-permeability cores using nuclear magnetic resonance (NMR). Fuel 2019, 263, 116648 .

AMA Style

Songyan Li, Qun Wang, Kaiqiang Zhang, Zhaomin Li. Monitoring of CO2 and CO2 oil-based foam flooding processes in fractured low-permeability cores using nuclear magnetic resonance (NMR). Fuel. 2019; 263 ():116648.

Chicago/Turabian Style

Songyan Li; Qun Wang; Kaiqiang Zhang; Zhaomin Li. 2019. "Monitoring of CO2 and CO2 oil-based foam flooding processes in fractured low-permeability cores using nuclear magnetic resonance (NMR)." Fuel 263, no. : 116648.

Journal article
Published: 01 November 2019 in Journal of Colloid and Interface Science
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In this paper, a factorial analysis approach is applied to characterize the potential single and interactive factors as well as their effects on the interface and miscibility of three light oil-CO2 systems under 32 different conditions. First, a modified Peng-Robinson equation of state coupled with the parachor model is applied to calculate the vapour-liquid equilibrium and interfacial tensions (IFTs) at a variation of pore radii and different pressures, based on which the MMPs are determined from the diminishing interface method. Second, by means of the factorial-analysis approach and calculated IFTs and minimum miscibility pressures (MMPs), the following five factors are specifically studied to evaluate their main and interactive effects on the IFTs and MMPs: temperature, initial oil and gas compositions, feed gas to oil ratio (feed GOR), and pore radius. It is found that the main and interactive effects of the five factors on the IFTs are inconsistent at different pressures. The effects of the five factors on the MMPs are evaluated quantitatively, which contribute to screen out significant factors, analyze interactions, and identify schemes for the miscible CO2 enhanced oil recovery. The most positive significant main and interactive effects on the MMPs are Factors C (gas composition) and AB (temperature and oil composition), whereas the most negative results are Factors E (pore radius) and AC (temperature and gas compositions). A three-factor analysis indicates that the MMP is substantially reduced in small pores by controlling the percentage of the CH4-dominated gas in the impure CO2 sample and lowering the feed GOR.

ACS Style

Kaiqiang Zhang; Zhan Meng; Lirong Liu. Factorial two-stage analyses of parameters affecting the oil–gas interface and miscibility in bulk phase and nanopores. Journal of Colloid and Interface Science 2019, 555, 740 -750.

AMA Style

Kaiqiang Zhang, Zhan Meng, Lirong Liu. Factorial two-stage analyses of parameters affecting the oil–gas interface and miscibility in bulk phase and nanopores. Journal of Colloid and Interface Science. 2019; 555 ():740-750.

Chicago/Turabian Style

Kaiqiang Zhang; Zhan Meng; Lirong Liu. 2019. "Factorial two-stage analyses of parameters affecting the oil–gas interface and miscibility in bulk phase and nanopores." Journal of Colloid and Interface Science 555, no. : 740-750.

Research article
Published: 30 October 2019 in Industrial & Engineering Chemistry Research
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In this paper, a comprehensive research including laboratory experiments and theoretical models is conducted to investigate the diffusion behavior of supercritical CO2 in micro- and nanoconfined pores. First, a total of five diffusion tests with five different-permeability core samples are conducted to determine CO2 diffusion coefficients in porous media. Second, a diffusion model, which comprises a straightforward physical model and series of mathematical formulations, is developed to evaluate the diffusion process in micro- to nanoconfined pores coupled. Core samples and reservoir fluids are specifically characterized. The micro- and nanometer-scale pores are found to be complex in pore structure with high textural coefficient and tortuosity. The phase behavior of reservoir fluids is found to substantially change when the permeability and pore radius are less than 0.001 mD and 0.1 μm, respectively. The CO2 diffusion in the crude oil-saturated micro- and nanoconfined pores is categorized as the bulk and Knudsen diffusion, whose diffusion coefficient is determined from the pressure-decay method. More specifically, the CO2 diffusion coefficient is increased with the permeability and pore radius increase. Furthermore, the reduced permeability/pore radius lower than 0.1 μm leads to a smaller diffusion coefficient by including the critical shifts at the same pore scale.

ACS Style

Songyan Li; Yifan Wang; Kaiqiang Zhang; Chenyu Qiao. Diffusion Behavior of Supercritical CO2 in Micro- to Nanoconfined Pores. Industrial & Engineering Chemistry Research 2019, 58, 21772 -21784.

AMA Style

Songyan Li, Yifan Wang, Kaiqiang Zhang, Chenyu Qiao. Diffusion Behavior of Supercritical CO2 in Micro- to Nanoconfined Pores. Industrial & Engineering Chemistry Research. 2019; 58 (47):21772-21784.

Chicago/Turabian Style

Songyan Li; Yifan Wang; Kaiqiang Zhang; Chenyu Qiao. 2019. "Diffusion Behavior of Supercritical CO2 in Micro- to Nanoconfined Pores." Industrial & Engineering Chemistry Research 58, no. 47: 21772-21784.

Research article
Published: 17 September 2019 in Energy Science & Engineering
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Flue gas collection from steam generators and its utilization in enhanced oil recovery (EOR) can reduce CO2 emissions into the atmosphere and improve oil recovery efficiency. Under the environments of flue gas corrosion in oilfields, the effects of corrosion time, temperature, pressure, velocity, and concentrations of O2, SO2, H2O, and NaCl on corrosion rates of steels used for a downhole string were investigated through physical simulation experiments. The corrosion mechanisms were analyzed by component, and the morphology of the corrosion products tested by X‐ray diffraction (XRD) and scanning electron microscopy (SEM). In the gas phase, the corrosion rates of X70, P110, and N80 notably increase with temperature and O2 concentration. The corrosion rates first increase rapidly with pressure from 1.0 to 3.0 MPa and then remain largely stable. Meanwhile, the corrosion rates of X70, P110, and N80 in the liquid phase first increase and then decrease with temperature and reach maximum values at 90°C. The corrosion rates of X70, P110, and N80 increase notably with velocity and the concentrations of O2, SO2, H2O, and NaCl. The corrosion rate of 13Cr is considerably lower than those of N80, P110, and X70, which shows good corrosion resistance performance. To reduce the flue gas corrosion of a downhole string, the relative humidity of the flue gas should be lower than 0.7, the temperature of the flue gas in the wellbore should avoid the range between 80 and 100°C, the excess air coefficient of the boiler should be kept at a reasonable value to reduce the O2 content in the flue gas, and the flue gas should not be coinjected into wellbores with brine. The injection of flue gas is technically feasible considering the corrosion of downhole string.

ACS Style

Songyan Li; Kaiqiang Zhang; Qun Wang. Experimental study on the corrosion of a downhole string under flue gas injection conditions. Energy Science & Engineering 2019, 7, 2620 -2632.

AMA Style

Songyan Li, Kaiqiang Zhang, Qun Wang. Experimental study on the corrosion of a downhole string under flue gas injection conditions. Energy Science & Engineering. 2019; 7 (6):2620-2632.

Chicago/Turabian Style

Songyan Li; Kaiqiang Zhang; Qun Wang. 2019. "Experimental study on the corrosion of a downhole string under flue gas injection conditions." Energy Science & Engineering 7, no. 6: 2620-2632.

Journal article
Published: 26 August 2019 in Applied Energy
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Understanding and controlling confined CO2 fluids in nanopores is at the heart of the CO2 enhanced oil recovery in shale reservoirs. Here, for the first time, qualitative and quantitative static and dynamic behavior of complex confined CO2 fluids in dual-scale nanopores are experimentally performed in nanofluidics, which combines with the theoretical model, the statistical mechanics coupled with the thermodynamic equation of state, to investigate the CO2 utilization in shale reservoirs. In experiment, a series of phase behavior and fluid flow laboratory tests are conducted through a self-manufactured nanofluidic system at different conditions; in theory, a generalized equation of state including the confinements and pore-size distributions and five dynamic models are developed and applied to calculate the vapor–liquid equilibrium and fluid dynamics. Results from this study show that the static behavior has drastic changes in the dual-scale nanopores that the measured saturation pressure of the confined CO2–C10 fluids reduces by 10.19% at T = 25.0 °C and 7.26% at T = 53.0 °C from bulk phase to nanometer scale. Furthermore, under the strong confinements in the dual-scale nanopores, the calculated phase properties including the pore-size distribution effects are more accurate. In addition, effects of the temperature and feed gas to liquid ratio on the confined fluids in nanopores share similar manners with the bulk phase cases. The proposed theoretical models are capable of calculating the static and dynamic behavior of the confined fluids and all calculations have been validated by the experimentally measured results. This study supports the foundation of more general applications pertaining to producing shale fluids and sequestrating CO2 in shale reservoir characterization and exploration.

ACS Style

Kaiqiang Zhang; Na Jia; Songyan Li; Lirong Liu. Static and dynamic behavior of CO2 enhanced oil recovery in shale reservoirs: Experimental nanofluidics and theoretical models with dual-scale nanopores. Applied Energy 2019, 255, 113752 .

AMA Style

Kaiqiang Zhang, Na Jia, Songyan Li, Lirong Liu. Static and dynamic behavior of CO2 enhanced oil recovery in shale reservoirs: Experimental nanofluidics and theoretical models with dual-scale nanopores. Applied Energy. 2019; 255 ():113752.

Chicago/Turabian Style

Kaiqiang Zhang; Na Jia; Songyan Li; Lirong Liu. 2019. "Static and dynamic behavior of CO2 enhanced oil recovery in shale reservoirs: Experimental nanofluidics and theoretical models with dual-scale nanopores." Applied Energy 255, no. : 113752.

Journal article
Published: 21 August 2019 in Fuel
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Since its initial proposal, steam-assisted gravity drainage (SAGD) has become a key technology of heavy-oil recovery. Due to the large heat loss and high energy consumption in the SAGD process, gas-assisted SAGD is a way to improve the efficiency. In this paper, a two-dimensional (2D) visualization simulation experiment of SAGD is introduced. By adjusting the volume ratio of steam to nitrogen, the proportion for the nitrogen-assisted SAGD process is optimized based on a homogeneous model. The 2D visualization simulation experiment of a heterogeneous model is carried out by adjusting the length of a low-permeability interlayer. The results of the SAGD simulation experiment and nitrogen-assisted SAGD simulation experiment are analyzed. The effect of nitrogen on breaking through and bypassing the low-permeability interlayer is discussed. The experimental results show that the optimal volume ratio of steam to nitrogen is 8:2 in the process of nitrogen-assisted SAGD. At this volume ratio, the sweep efficiency, recovery factor and cumulative oil-steam ratio are the largest, and the recovery factor reaches up to 49.12%. The experimental results for the heterogeneous model with the low-permeability interlayer show that nitrogen can synergistically promote steam to break through the fully occluding interlayer and bypass partially occluding interlayers. Comparing the results of the SAGD simulation with those of the nitrogen-assisted SAGD simulation for the heterogeneous model with the low-permeability interlayer, it is found that the sweep efficiency of steam increases from 34.24% to 43.12%. This result can be explained by the effect of nitrogen on expanding the steam-swept area in the SAGD process and the synergistic action between nitrogen and steam.

ACS Style

Songyan Li; Tingting Yu; Zhaomin Li; Kaiqiang Zhang. Experimental investigation of nitrogen-assisted SAGD in heavy-oil reservoirs: A two-dimensional visual analysis. Fuel 2019, 257, 116013 .

AMA Style

Songyan Li, Tingting Yu, Zhaomin Li, Kaiqiang Zhang. Experimental investigation of nitrogen-assisted SAGD in heavy-oil reservoirs: A two-dimensional visual analysis. Fuel. 2019; 257 ():116013.

Chicago/Turabian Style

Songyan Li; Tingting Yu; Zhaomin Li; Kaiqiang Zhang. 2019. "Experimental investigation of nitrogen-assisted SAGD in heavy-oil reservoirs: A two-dimensional visual analysis." Fuel 257, no. : 116013.