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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.
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 StyleGuangwei 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 StyleGuangwei 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.
Analytical modeling of CO2 flow is essential for the rapid evaluation of CO2 plume evolution and possible leakage risk during geological carbon sequestration (GCS). Here we adapt the model of describing the secondary migration of oil proposed by Siddiqui and Lake (1992) to characterize CO2 upward migration and backfilling for buoyant and countercurrent flow in a saline aquifer. Both water- and CO2-wet reservoirs are examined under typical buoyant fluxes. We present self-similar solutions of CO2 saturation waves without capillary pressure and traveling wave solutions after adding capillarity. We demonstrate that saturation wave types, CO2 migration, and saturation profiles are influenced by buoyant flux, capillary pressure, wettability, and relative permeability. The stabilized zones resulting from capillary dispersion inside a CO2-wet reservoir generally extend wider than those for a water-wet reservoir. The presented model and results are potentially useful to understand field scale CO2 plume behaviors as well as to guide the design of corefloods for studying CO2 buoyant flow characteristics.
Bo Ren; Hoonyoung Jeong. Buoyant and countercurrent flow of CO2 with capillary dispersion. Journal of Petroleum Science and Engineering 2020, 195, 107922 .
AMA StyleBo Ren, Hoonyoung Jeong. Buoyant and countercurrent flow of CO2 with capillary dispersion. Journal of Petroleum Science and Engineering. 2020; 195 ():107922.
Chicago/Turabian StyleBo Ren; Hoonyoung Jeong. 2020. "Buoyant and countercurrent flow of CO2 with capillary dispersion." Journal of Petroleum Science and Engineering 195, no. : 107922.
Local capillary trapping occurs when buoyant CO2 moves upward in a saline aquifer during geologic carbon sequestration. The volumetric capacity of local capillary traps (LCTs) is controlled by reservoir geological heterogeneity. These traps are thus intrinsic to heterogeneous storage aquifers; their volumetric capacities are however largely unknown. To address this issue, this work employs an easily calculated criterion that requires only a static geologic model to estimate the properties of LCT clusters, including size, frequency, and extent. Specifically, this work quantitatively analyzes: i) the properties of the largest LCT cluster; and ii) the impact of reservoir heterogeneity on cluster properties. The key finding of this work is that spatially-correlated reservoir heterogeneity in the horizontal direction causes the largest LCT cluster to laterally span across a given domain even when the horizontal correlation length is small (only 1/25th) compared to the domain width. The overall work sheds useful insights of the dependence of LCT clusters on reservoir heterogeneity and its implication for CO2 trapping quantification.
Bo Ren; Luca Trevisan. Characterization of local capillary trap clusters in storage aquifers. Energy 2019, 193, 116795 .
AMA StyleBo Ren, Luca Trevisan. Characterization of local capillary trap clusters in storage aquifers. Energy. 2019; 193 ():116795.
Chicago/Turabian StyleBo Ren; Luca Trevisan. 2019. "Characterization of local capillary trap clusters in storage aquifers." Energy 193, no. : 116795.
Capillary pressure heterogeneity causes local capillary trapping of CO2 in saline aquifers. However, quantifying local capillary trapping using conventional reservoir simulation is computationally intensive. This work employs a geologic criterion (GC) to rapidly estimate the volume capacity of local capillary traps in static geologic models. The criterion refers to the ‘critical capillary entry pressure’ that is used to indicate flow barriers and flow paths during buoyant flow. A previous study (Saadatpoor, 2012) found that issues exist in the criterion method: unknown physical critical capillary entry pressures and boundary barriers. This work addresses the two issues. It is shown that the criterion method gives a close upper bound estimation of local capillary trap volume capacities. Several fine-scale geostatistical realizations of capillary entry pressure fields are considered, and the effects of reservoir heterogeneity, system sizes, aspect ratios, and boundary types are examined. The results from the GC are also strictly interpreted through invoking a simple counting argument. The overall work enhances our mechanistic understanding of the geological controls of local capillary traps.
Bo Ren; Steven L. Bryant; Larry W. Lake. Estimating local capillary trap volume capacities using a geologic criterion. International Journal of Greenhouse Gas Control 2019, 85, 46 -57.
AMA StyleBo Ren, Steven L. Bryant, Larry W. Lake. Estimating local capillary trap volume capacities using a geologic criterion. International Journal of Greenhouse Gas Control. 2019; 85 ():46-57.
Chicago/Turabian StyleBo Ren; Steven L. Bryant; Larry W. Lake. 2019. "Estimating local capillary trap volume capacities using a geologic criterion." International Journal of Greenhouse Gas Control 85, no. : 46-57.
Residual oil zones (ROZs) are extensively developed in carbonate formations in the Permian Basin, West Texas. These ROZs have the potential both for economically-viable CO2 enhanced oil recovery (CO2-EOR) and for significant volumes of associated CO2 sequestration. The accepted model for ROZ formation is based on the hydrodynamic effects of tectonically-controlled increased water flow in aquifers at the base of oil fields. The nature of this process is modelled using a commercial reservoir simulator in this work. These simulations explore the effects of strength of aquifer flow, flow direction, and capillary pressure on the nature and distribution of oil saturations in ROZs. A special emphasis was on understanding the impact of heterogeneity of capillary pressures in ROZ reservoirs. These factors determine the thickness of ROZs, the magnitude of oil saturation, and the slope of water-oil contacts. Understanding the magnitude of oil saturation and how it varies within ROZs is important in determining reserves, and evaluating both EOR and sequestration potential. The geometry of ROZs are established slowly, especially for small regional water fluxes, however oil saturations achieve almost steady states in relatively short time scales. The simulated oil saturation profiles found in this study are in reasonable agreement with the measured profile published for the San Andres Seminole Unit's ROZ. The results support the plausibility of the hydrodynamic model, but do not rule out other models for the origin of ROZs.
Bo Ren; Ian Duncan. Modeling oil saturation evolution in residual oil zones: Implications for CO2 EOR and sequestration. Journal of Petroleum Science and Engineering 2019, 177, 528 -539.
AMA StyleBo Ren, Ian Duncan. Modeling oil saturation evolution in residual oil zones: Implications for CO2 EOR and sequestration. Journal of Petroleum Science and Engineering. 2019; 177 ():528-539.
Chicago/Turabian StyleBo Ren; Ian Duncan. 2019. "Modeling oil saturation evolution in residual oil zones: Implications for CO2 EOR and sequestration." Journal of Petroleum Science and Engineering 177, no. : 528-539.
Residual oil zones (ROZs) are reservoirs in which oil is largely at levels of residual saturation. Such reservoirs cannot be produced by conventional techniques; rather some forms of enhanced oil recovery (EOR), such as CO2 injection is required. As a result, these zones have a potential for CO2 storage associated with EOR activities. In West Texas, the oil production potential of these zones, associated with the San Andres Formation alone, has been estimated as on the order of tens of billions of barrels. A series of numerical simulations of CO2 miscible flooding were conducted on 11 Sub-Volumes cut from a larger static reservoir that represents the range of heterogeneity in permeability and porosity found in San Andres ROZs. This work set out to evaluate the effects of injection strategies and reservoir heterogeneities on the performance of CO2 sequestration. The injection techniques investigated were: continuous CO2 injection and water alternating gas (WAG). Multiple factors were examined, including domain boundary conditions, well patterns, injection rates, permeability anisotropy, and natural fractures. It was found that ROZs could have higher retention fractions (i.e., volume fraction of injected CO2 retained in ROZs) for a combination of inverted five-spot well patterns and large WAG ratios. Based on the results of these numerical simulations, the long-term potential for CO2 storage associated with CO2-EOR of ROZs can be assessed. Our results provide key insights into how future CO2 storage projects associated with EOR in ROZs within carbonate sequences may be implemented.
Bo Ren; Ian J. Duncan. Reservoir simulation of carbon storage associated with CO2 EOR in residual oil zones, San Andres formation of West Texas, Permian Basin, USA. Energy 2018, 167, 391 -401.
AMA StyleBo Ren, Ian J. Duncan. Reservoir simulation of carbon storage associated with CO2 EOR in residual oil zones, San Andres formation of West Texas, Permian Basin, USA. Energy. 2018; 167 ():391-401.
Chicago/Turabian StyleBo Ren; Ian J. Duncan. 2018. "Reservoir simulation of carbon storage associated with CO2 EOR in residual oil zones, San Andres formation of West Texas, Permian Basin, USA." Energy 167, no. : 391-401.
Local capillary trapping (LCT) of CO2 is caused by the intrinsic heterogeneity of storage aquifers. It is computationally intensive to model LCT using conventional reservoir flow simulators. This work proposes a fast proxy method. We decouple the LCT modeling into two parts: permeability-based flow simulation using a connectivity analysis, and identification of local capillary traps (capillary entry pressure-based) using a geologic criterion. The connectivity analysis is employed to rapidly approximate CO2 plume evolution through estimating the arrival time of CO2. This analysis uses the geostatistical realization of permeability fields as input. The geologic criteria algorithm is used to estimate the potential local capillary traps from a given capillary entry pressure field. This field, through the Leverett j-function, is correlated to the permeability field used in the connectivity analysis. We then quantify the total volume of local capillary traps identified within the capillary entry pressure field that can be filled during CO2 migration. We conduct several simulations in the reservoirs with different levels of heterogeneity under various injection scenarios. We demonstrate the reservoir heterogeneity affects the optimal injection rate in maximizing LCT during CO2 injection. This work enhances our understanding of the effects of injections strategies on LCT.
Bo Ren; Hoonyoung Jeong. Influence of injection strategies on local capillary trapping during geological carbon sequestration in saline aquifers. Journal of CO2 Utilization 2018, 27, 441 -449.
AMA StyleBo Ren, Hoonyoung Jeong. Influence of injection strategies on local capillary trapping during geological carbon sequestration in saline aquifers. Journal of CO2 Utilization. 2018; 27 ():441-449.
Chicago/Turabian StyleBo Ren; Hoonyoung Jeong. 2018. "Influence of injection strategies on local capillary trapping during geological carbon sequestration in saline aquifers." Journal of CO2 Utilization 27, no. : 441-449.
Local capillary trapping (LCT) is the trapping of CO2 by local capillary barriers. It occurs during buoyancy-driven migration of bulk phase CO2 within a saline aquifer exhibiting spatially varying properties (permeability and capillary entry pressure). The benefit of LCT, in the context of CO2 sequestration, is that local capillary trapped CO2 is not susceptible to leakage through failed seals. However, it is unclear how the petrophsyical/geological properties and flow dynamics influence LCT. Thus, the objective of this work is to evaluate the degree to which potential local capillary traps are filled and quantify the extent of immobilization persisting after loss of seal integrity. This paper presents a systematic and thorough study of the influential parameters of LCT. Fine-scale capillary pressure fields are generated by using geostatistical permeability realizations and applying the Leverett j-function. Multiple factors are examined, including injection rate, anisotropy, formation dip, aquifer types, residual gas saturation, and capillary hysteresis. Leakage representative of wellbore failure is simulated, and LCT after leakage is evaluated and compared to other trapping mechanisms. The results show that local capillary traps in the near-well region can be fully filled during injection. Moreover, they remain filled after post-injection buoyancy-driven flow ends. The filling efficiency of local capillary traps increases with the decrease in gravity number (ratio of buoyant force over viscous force). As a result, maximizing LCT in carbon sequestration in porous reservoirs may be achievable with the implementation of appropriate injection strategies.
Bo Ren. Local capillary trapping in carbon sequestration: Parametric study and implications for leakage assessment. International Journal of Greenhouse Gas Control 2018, 78, 135 -147.
AMA StyleBo Ren. Local capillary trapping in carbon sequestration: Parametric study and implications for leakage assessment. International Journal of Greenhouse Gas Control. 2018; 78 ():135-147.
Chicago/Turabian StyleBo Ren. 2018. "Local capillary trapping in carbon sequestration: Parametric study and implications for leakage assessment." International Journal of Greenhouse Gas Control 78, no. : 135-147.
Summary The main objective of this work is to understand, by analytical and numerical study, how permeability retardation interacts with capillary-barrier trapping to cause accumulation as carbon dioxide (CO2) migrates upward in saline aquifers during geological sequestration. The study is of one-dimensional (1D) two-phase (CO2 and water) countercurrent flow. The analytical model describes CO2 buoyant migration and accumulation at a “flow-barrier zone” (low permeability) above a “flow-path zone” (high permeability). The relative importance of permeability retardation and capillary trapping is examined under different magnitudes of buoyant-source fluxes and porous-media properties. In the limiting case of zero capillary pressure, the model equation is solved using the method of characteristics (MOC). Permeability-retarded accumulation, induced by the permeability difference between the flow path and the barrier zone, is illustrated through CO2-saturation profiles and time/distance diagrams. Capillary trapping is subsequently accounted for by graphically incorporating a capillary pressure curve and capillary-threshold effect. Results demonstrate that the accumulation contributions from both the permeability hindrance and capillary trapping are convolved at sufficiently large fluxes. At a given time, the total CO2 accumulated by permeability hindrance is greater than that accumulated by capillary trapping, but the former approaches the latter at large time. The low-permeability zone need not be completely impermeable for accumulation to occur. We demonstrate that considering only capillary trapping understates the amount of CO2 accumulated beneath low-permeability structures during significant periods of a sequestration operation.
Bo Ren; Jennifer M. Delaney; Larry W. Lake; Steven L. Bryant. Interplay Between Permeability Retardation and Capillary Trapping of Rising Carbon Dioxide in Storage Reservoirs. SPE Journal 2018, 23, 1866 -1879.
AMA StyleBo Ren, Jennifer M. Delaney, Larry W. Lake, Steven L. Bryant. Interplay Between Permeability Retardation and Capillary Trapping of Rising Carbon Dioxide in Storage Reservoirs. SPE Journal. 2018; 23 (5):1866-1879.
Chicago/Turabian StyleBo Ren; Jennifer M. Delaney; Larry W. Lake; Steven L. Bryant. 2018. "Interplay Between Permeability Retardation and Capillary Trapping of Rising Carbon Dioxide in Storage Reservoirs." SPE Journal 23, no. 5: 1866-1879.
During the last 10 years, a series of megaprojects have been implemented to develop new areas and improve the recovery factor of mature oilfields in Bohai Bay, and the oil equivalent of Bohai has kept steady for more than 188 MMbbls for 6 years. There were many challenges in front of the comprehensive adjustment of mature oilfields including difficulties of engineering facilities upgrading, inter well anti-collision, complexity of remaining oil distribution. Driven by the needs of the project, the conductor was innovative and bold in marine engineering, drilling and completion, reservoir engineering to reduce risk, improve efficiency and increase the IRR (internal rate of return). The redevelopment project of S&Q oilfields was a typical example which included 1 FPSO upgrading, 10 platforms, 300 kilometers submarine pipeline and cable, and more than 370 infill wells.
Hongfu Shi; Kuiqian Ma; Yifan He; Xiaodong Han; Bo Ren. A Comprehensive Innovation Method to Assess Uncertainties and Increase Performance of Infill Project in Mature Oilfields. Day 1 Mon, April 30, 2018 2018, 1 .
AMA StyleHongfu Shi, Kuiqian Ma, Yifan He, Xiaodong Han, Bo Ren. A Comprehensive Innovation Method to Assess Uncertainties and Increase Performance of Infill Project in Mature Oilfields. Day 1 Mon, April 30, 2018. 2018; ():1.
Chicago/Turabian StyleHongfu Shi; Kuiqian Ma; Yifan He; Xiaodong Han; Bo Ren. 2018. "A Comprehensive Innovation Method to Assess Uncertainties and Increase Performance of Infill Project in Mature Oilfields." Day 1 Mon, April 30, 2018 , no. : 1.
Cichoric acid (CA), extracted from edible plants and vegetables, is a potential natural nutraceutical, with antioxidant and hypoglycaemic biological functions. The objective of this study was to explore the potential underlying molecular mechanisms involved in normalizing diabetes-related changes in hyperglycaemia via pancreas apoptosis and muscle injury induced by multiple low-dose STZ (MLD-STZ) injection in response to dietary supplementation with CA. To induce the MLD-STZ diabetic mice, the C57BL/6J mice were intraperitoneally injected with STZ (50 mg/kg body weight) for consecutive five days. CA (60 mg/kg/d) was supplemented in drinking water for 4 weeks. Compared with control, CA inhibited pancreas apoptosis and adjusted islet function in diabetic mice, leading to an increase in insulin generation and secretion. Moreover, CA regulated mitochondrial biogenesis, glycogen synthesis, and inhibited inflammation via activating antioxidant responses, which contributes to the improvement in athletic ability and diabetic myopathy. In general, CA is a natural food-derived compound with the potential application for regulating glucose homeostasis and improving diabetes and its complications.
Di Zhu; Xinglin Zhang; Yajie Niu; Zhijun Diao; Bo Ren; Xingyu Li; Zhigang Liu; Xuebo Liu. Cichoric acid improved hyperglycaemia and restored muscle injury via activating antioxidant response in MLD-STZ-induced diabetic mice. Food and Chemical Toxicology 2017, 107, 138 -149.
AMA StyleDi Zhu, Xinglin Zhang, Yajie Niu, Zhijun Diao, Bo Ren, Xingyu Li, Zhigang Liu, Xuebo Liu. Cichoric acid improved hyperglycaemia and restored muscle injury via activating antioxidant response in MLD-STZ-induced diabetic mice. Food and Chemical Toxicology. 2017; 107 ():138-149.
Chicago/Turabian StyleDi Zhu; Xinglin Zhang; Yajie Niu; Zhijun Diao; Bo Ren; Xingyu Li; Zhigang Liu; Xuebo Liu. 2017. "Cichoric acid improved hyperglycaemia and restored muscle injury via activating antioxidant response in MLD-STZ-induced diabetic mice." Food and Chemical Toxicology 107, no. : 138-149.
Guodong Cui; Liang Zhang; Bo Ren; Chioma Enechukwu; Yanmin Liu; Shaoran Ren. Geothermal exploitation from depleted high temperature gas reservoirs via recycling supercritical CO2: Heat mining rate and salt precipitation effects. Applied Energy 2016, 183, 837 -852.
AMA StyleGuodong Cui, Liang Zhang, Bo Ren, Chioma Enechukwu, Yanmin Liu, Shaoran Ren. Geothermal exploitation from depleted high temperature gas reservoirs via recycling supercritical CO2: Heat mining rate and salt precipitation effects. Applied Energy. 2016; 183 ():837-852.
Chicago/Turabian StyleGuodong Cui; Liang Zhang; Bo Ren; Chioma Enechukwu; Yanmin Liu; Shaoran Ren. 2016. "Geothermal exploitation from depleted high temperature gas reservoirs via recycling supercritical CO2: Heat mining rate and salt precipitation effects." Applied Energy 183, no. : 837-852.
Liang Zhang; Guodong Cui; Yin Zhang; Bo Ren; Shaoran Ren; Xiaohui Wang. Influence of pore water on the heat mining performance of supercritical CO2 injected for geothermal development. Journal of CO2 Utilization 2016, 16, 287 -300.
AMA StyleLiang Zhang, Guodong Cui, Yin Zhang, Bo Ren, Shaoran Ren, Xiaohui Wang. Influence of pore water on the heat mining performance of supercritical CO2 injected for geothermal development. Journal of CO2 Utilization. 2016; 16 ():287-300.
Chicago/Turabian StyleLiang Zhang; Guodong Cui; Yin Zhang; Bo Ren; Shaoran Ren; Xiaohui Wang. 2016. "Influence of pore water on the heat mining performance of supercritical CO2 injected for geothermal development." Journal of CO2 Utilization 16, no. : 287-300.
Guodong Cui; Shaoran Ren; Liang Zhang; Bo Ren; Yuan Zhuang; Xin Li; Bo Han; Panfeng Zhang. Formation water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs. Petroleum Exploration and Development 2016, 43, 815 -824.
AMA StyleGuodong Cui, Shaoran Ren, Liang Zhang, Bo Ren, Yuan Zhuang, Xin Li, Bo Han, Panfeng Zhang. Formation water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs. Petroleum Exploration and Development. 2016; 43 (5):815-824.
Chicago/Turabian StyleGuodong Cui; Shaoran Ren; Liang Zhang; Bo Ren; Yuan Zhuang; Xin Li; Bo Han; Panfeng Zhang. 2016. "Formation water evaporation induced salt precipitation and its effect on gas production in high temperature natural gas reservoirs." Petroleum Exploration and Development 43, no. 5: 815-824.
A CO2 EOR and storage pilot test have been conducted in the H-59 block of Jilin oilfield China for well seven years. It is important to track the CO2 storage and distribution in the reservoir, which can provide valuable guidance for the operation in the next stage of the project. In this paper, the CO2 storage capacity in the H-59 block was calculated by considering various CO2 trapping mechanisms, and the distribution and trapping status of the stored CO2 were evaluated by using the reservoir simulation method. The effective CO2 storage capacity in the H-59 block is estimated to be 26.37 × 104 ton by incorporating the CO2 sweep efficiency and neglecting the mineral trapping. Up to June 2014, 21.08 × 104 ton of CO2 has been injected with over 95% stored. The geological structure of the H-59 block controls most of the injected CO2 moving only along the horizontal direction in the thin oil layers. The shape and size of the CO2 plume are mainly determined by the reservoir heterogeneity, well pattern and injected CO2 amount. According to the assessment results, the CO2 sweep efficiency within each well group varies from 20% to 80%. About 42.68–60.15% of the stored CO2 has been trapped at supercritical state accompanied with 24.85–41.8% and 15% of the stored CO2 dissolved in residual oil and water, respectively. The H-59 block still has a potentially remaining capacity of 6.25 × 104 ton of CO2 for the future storage. Necessary engineering measures might be taken to further increase the sweep and displacement efficiencies of CO2 to achieve this purpose.
Liang Zhang; Xin Li; Bo Ren; Guodong Cui; Yin Zhang; Shaoran Ren; Guoli Chen; Hua Zhang. CO 2 storage potential and trapping mechanisms in the H-59 block of Jilin oilfield China. International Journal of Greenhouse Gas Control 2016, 49, 267 -280.
AMA StyleLiang Zhang, Xin Li, Bo Ren, Guodong Cui, Yin Zhang, Shaoran Ren, Guoli Chen, Hua Zhang. CO 2 storage potential and trapping mechanisms in the H-59 block of Jilin oilfield China. International Journal of Greenhouse Gas Control. 2016; 49 ():267-280.
Chicago/Turabian StyleLiang Zhang; Xin Li; Bo Ren; Guodong Cui; Yin Zhang; Shaoran Ren; Guoli Chen; Hua Zhang. 2016. "CO 2 storage potential and trapping mechanisms in the H-59 block of Jilin oilfield China." International Journal of Greenhouse Gas Control 49, no. : 267-280.
QHD oilfield in Bohai Bay, China, is characterized by conventional heavy oil (average viscosity 150cp under reservoir conditions) with excellent reservoir quality (up to 30% porosity and 1-2D permeability) and strong aquifer. Horizontal and multilateral wells are widely used in QHD and most wells were standard completion. After 13 years of development, many wells show sharp production decline and rapid water cut increase. What's more, water breakthrough in several wells is much earlier than prediction. The high mobility ratio, hell-toe effect, bottom water, permeability heterogeneity and sand are contributed to reduced ultimate recovery and well life. The use of ICD (inflow control device) is becoming more and more prevalent as it can delay the water break through and significantly improve the economic life of a well. This is especially important for offshore fields where well intervention is difficult and expensive. Therefore, ICD technique is proposed to address the above production problem while prolonging production life (BREKKE K, 1997). In this paper, I discuss the feasibility of ICD for horizontal wells in heavy oil reservoir of offshore field. First, I analyze the actuality of the offshore heavy oil with strong bottom water in Bohai Bay and the reason of bottom water coning. Secondly, I discuss the feasibility of ICD for horizontal wells in heavy oil reservoir of offshore field. Finally, a new method is established to design the additional pressure of ICD. The method is compared to the uniform liquid method; what's more, a numerical model is developed to validate the new method. The production performance of the first ICD wells was discussed to provide evidence on its effectiveness and robustness. This has provided valuable data prior to well drilling and the final optimization of ICD. The paper demonstrates the importance of seamless teamwork and coordination between reservoir engineers and project team to deliver superior performance. In a word, this paper is expected to assist well completion decisions for offshore heavy oil reservoir and to spark continue research on ICD.
Hongfu Shi; Haiyan Zhou; Yong Hu; Yifan He; Rong Fu; Bo Ren. A New Method to Design and Optimize the ICD for Horizontal Wells. Day 4 Thu, May 05, 2016 2016, 1 .
AMA StyleHongfu Shi, Haiyan Zhou, Yong Hu, Yifan He, Rong Fu, Bo Ren. A New Method to Design and Optimize the ICD for Horizontal Wells. Day 4 Thu, May 05, 2016. 2016; ():1.
Chicago/Turabian StyleHongfu Shi; Haiyan Zhou; Yong Hu; Yifan He; Rong Fu; Bo Ren. 2016. "A New Method to Design and Optimize the ICD for Horizontal Wells." Day 4 Thu, May 05, 2016 , no. : 1.
Foam injection is a proven technique for improved oil recovery in both light and heavy oil reservoirs, especially for those with high heterogeneity, in which foam can improve the displacement and sweeping efficiency effectively. In this study, the feasibility of nitrogen foam injection for IOR from viscous oil reservoirs are investigated via laboratory experiments and field pilot analysis. The targeted oilfield is located offshore Bohai Bay (China), featured with high oil viscosity (up to 924 mPa.s) and severe heterogeneity of pay-zones. Water flooding has been applied in the oilfield, but the recovery factor is less than 20% and high water cut (over 85%) has been observed. Nitrogen foam injection was proposed in order to solve the problems and improve oil recovery. In this study, laboratory evaluation of nitrogen foam was conducted via foam testing and sandpack flooding. The results indicate that polymer enhanced foaming agents can greatly increase foam's performance. High blocking capability and displacement efficiency were observed in enhanced foam flooding experiments, indicating that nitrogen foam injection can mitigate the problems of heterogeneity and increase oil recovery in low permeability zones. A field pilot with 2 injectors and 13 producers involved has been conducted to verify the feasibility of the foam technique. The wellhead injection pressure was effectively increased after foam injection, and nearly all producers exhibited good response with incremental oil recovery and the average water cut dropped by 6.3% over 8 months of the field operation. The field pilot demonstrates the effectiveness of the nitrogen foam injection technique as an effective IOR method for the targeted oilfield and other similar oil reservoirs.
Y. M. Liu; L.. Zhang; S. R. Ren; Bo Ren; S. T. Wang; G. R. Xu. Injection of Nitrogen Foam for Improved Oil Recovery in Viscous Oil Reservoirs Offshore Bohai Bay China. All Days 2016, 1 .
AMA StyleY. M. Liu, L.. Zhang, S. R. Ren, Bo Ren, S. T. Wang, G. R. Xu. Injection of Nitrogen Foam for Improved Oil Recovery in Viscous Oil Reservoirs Offshore Bohai Bay China. All Days. 2016; ():1.
Chicago/Turabian StyleY. M. Liu; L.. Zhang; S. R. Ren; Bo Ren; S. T. Wang; G. R. Xu. 2016. "Injection of Nitrogen Foam for Improved Oil Recovery in Viscous Oil Reservoirs Offshore Bohai Bay China." All Days , no. : 1.
Jilin Oilfield is conducting a large-scale demonstration project on CO2 EOR (enhanced oil recovery) and storage in China. CO2 separated from a nearby natural gas reservoir (15–30 mol% CO2) is injected into the northern part of H59 oil block with permeability and porosity of 3.5 mD and 12.7%, respectively. After about six years of operation, nearly 0.26 million tons of CO2 (0.32 HCPV (hydrocarbon pore volume)) has been injected into the thin oil layers with well-developed natural fractures. In order to track the movement of CO2 in the oil reservoir, a microseismic monitoring program has been implemented to map the CO2 flow anisotropy and estimate its sweeping efficiency. Gas tracer testing has also been conducted to examine the inter-well connectivity. The temporal change of produced CO2 has been analyzed in a real-time mode to monitor the dynamic response in production wells. It is demonstrated that the migration of CO2 in the thin oil layers can be successfully detected by the microseismic technique, and the sweeping profiles of CO2 obtained from the inverted microseismic are in good agreement with the produced CO2 rate from production wells as well as the reservoir's petrophysical properties.
Bo Ren; Shaoran Ren; Liang Zhang; Guoli Chen; Hua Zhang. Monitoring on CO2 migration in a tight oil reservoir during CCS-EOR in Jilin Oilfield China. Energy 2016, 98, 108 -121.
AMA StyleBo Ren, Shaoran Ren, Liang Zhang, Guoli Chen, Hua Zhang. Monitoring on CO2 migration in a tight oil reservoir during CCS-EOR in Jilin Oilfield China. Energy. 2016; 98 ():108-121.
Chicago/Turabian StyleBo Ren; Shaoran Ren; Liang Zhang; Guoli Chen; Hua Zhang. 2016. "Monitoring on CO2 migration in a tight oil reservoir during CCS-EOR in Jilin Oilfield China." Energy 98, no. : 108-121.
CO2 capture and geological storage (CCS) is an effective method to solve the problem of greenhouse gas emission. The CO2 storage in saline aquifers has a promising future with huge storage capacity compared to other storage candidates. The storage in saline aquifers is feasible technically but storage safety is of the main concerns. In this paper, the seal mechanisms of cap rock was analyzed which showed the seal performance is much related to the interfacial tensions (IFT) of CO2-water binary mixture in a given reservoir. The influence of temperature, pressure, salinities and CO2 solubility on the IFT was investigated using Tracker rheometer. With increase of temperature and salinity, the IFT becomes higher. On the contrary, the IFT decreases as the pressure increases. Storage in saline aquifers with high salinity may have better seal performance of cap rock in terms of salinity influence on the IFT. By Spearman correlation coefficient analysis method, it shows good negative correlation between CO2 solubility and IFT with the value of -0.91, which indicates that the storage capacity and seal performance of cap rock should be taken into consideration at the same time during the selection process of CO2 storage locations.
D. Li; B. Ren; L. Zhang; Z. Yin; S. Ren. Experimental Study on the Interfacial Tensions of CO2-water Binary Mixture for CO2 Storage Safety. 78th EAGE Conference and Exhibition 2016 2016, 1 .
AMA StyleD. Li, B. Ren, L. Zhang, Z. Yin, S. Ren. Experimental Study on the Interfacial Tensions of CO2-water Binary Mixture for CO2 Storage Safety. 78th EAGE Conference and Exhibition 2016. 2016; ():1.
Chicago/Turabian StyleD. Li; B. Ren; L. Zhang; Z. Yin; S. Ren. 2016. "Experimental Study on the Interfacial Tensions of CO2-water Binary Mixture for CO2 Storage Safety." 78th EAGE Conference and Exhibition 2016 , no. : 1.
When CO2 migrates upwards under buoyancy in the subsurface saline aquifer and encounters local capillary barriers (regions of rock with large capillary entry pressure), CO2 would accumulate beneath these small barriers, and these accumulations are called local capillary trapping (LCT). LCT benefits storage because locally trapped CO2 has a much larger saturation than residual gas, and such trapped gases cannot escape from the formation even if leakage conduits (fractures or fault) in the seal develop during the long-term storage of CO2. Thus predicting and maximizing LCT is valuable in design and risk assessment of geologic storage projects. Modeling LCT is computationally expensive and may even be intractable by using a conventional reservoir simulator. In this work, we decouple the problem into two parts: permeability-based flow simulation and capillary entry pressure-based local capillary trapping phenomenon. The connectivity analysis originally developed for characterizing well-to-reservoir connectivity is adapted to the flow simulation by means of a newly defined edge weight property between neighboring grid blocks, which accounts for the multiphase flow properties, injection rate, and buoyancy effect. Then the connectivity was estimated from shortest path algorithm to predict the CO2 migration behavior and plume shape during injection. A geologic criteria algorithm is developed to estimate the potential LCT only from the entry capillary pressure field. The latter is correlated to a geostatistical realization of permeability field. The extended connectivity analysis shows a good match of CO2 plume computed by the full-physics simulation. We then incorporate it into the geologic algorithm to quantify the amount of LCT structures identified within the entry capillary pressure field that can be filled during CO2 injection. Several simulations were conducted in the reservoirs with different level of heterogeneity (measured by the Dykstra-Parsons coefficient) under various injection scenarios. We demonstrate the reservoir heterogeneity affects the optimal injection rate in maximizing the LCT during injection. Both the geologic algorithm and connectivity analysis are very fast; therefore, the integrated methodology can be used as a quick tool to estimate LCT. It can also be used as a potential complement to the full-physics simulation to evaluate the total safe storage capacity.
Bo Ren; Steven L. Bryant; Larry W. Lake. Fast Modeling of Local Capillary Trapping during CO2 Injection into a Saline Aquifer. All Days 2015, 1 .
AMA StyleBo Ren, Steven L. Bryant, Larry W. Lake. Fast Modeling of Local Capillary Trapping during CO2 Injection into a Saline Aquifer. All Days. 2015; ():1.
Chicago/Turabian StyleBo Ren; Steven L. Bryant; Larry W. Lake. 2015. "Fast Modeling of Local Capillary Trapping during CO2 Injection into a Saline Aquifer." All Days , no. : 1.