Low salinity relative permeability curves are required to estimate the benefit of low salinity waterflooding at the field-level. Low salinity benefit is measured from corefloods (i.e., at the plug scale) and the same benefit is often assumed in full field models to generate low salinity curves from high salinity curves (often pseudo curves). The validity of this assumption is investigated. We present how uncertainty distribution of low salinity benefit can be propagated through an ensemble of full field models in which each simulation case could have a set of distinctive high salinity pseudos. A 0.5-ft vertical resolution sector and its 10-ft upscaled counterpart are used. Low salinity benefit from corefloods is used to generate low salinity relative permeabilities for the high-resolution sector. Rock curves (relative permeability curves from corefloods) are used in the high-resolution sector to create "truth" profiles. Pseudo high and low salinity curves are generated for the upscaled sector by history matching high salinity and incremental low salinity truth case profiles. Low salinity benefit from the upscaled model is compared against that of high-resolution sector ("truth" model). It is crucial to include capillary pressure in high resolution models. In the case studied, analogue and published data are used to produce low salinity capillary pressure curves. Our results show that generating low salinity curves for high salinity pseudos using low salinity benefit from corefloods slightly underestimates the true low salinity benefit at field-scale (i.e., low salinity benefit estimated from high-resolution models). This conclusion is consistent for two extreme relative-permeability scenarios tested (i.e., a high total mobility-unfavorable fractional flow and low total mobility-favorable fractional flow). We demonstrate how a set of high salinity relative-permeability data obtained from corefloods, which encompasses a range for fractional flow and total mobility, can be included in ensemble modeling appropriately, and how low salinity benefit could be estimated for such an ensemble. It is adequate to generate low salinity curves for bounding high salinity sets of curves. The bounding low salinity curves can then be used to estimate low salinity curve for any interpolated high salinity curve. This significantly simplifies the process of generating a probability distribution function (pdf) of low salinity benefit for an ensemble of models, where each model has a different high salinity relative permeability. We explain the pseudoization process and how to generate a counterpart low salinity curve for a high salinity relative permeability that honors an estimated low salinity benefit from corefloods. We present how a pdf of low salinity benefit can be built for an ensemble of models with distinctive high salinity curves that each honors the low salinity benefit. The workflow simplifies the process of describing the uncertainty in the benefit of l
{"title":"Upscaling Low Salinity Benefit from Lab-Scale to Field-Scale - An Ensemble of Models with a Relative Permeability Uncertainty Range","authors":"Aboulghasem Kazemi Nia Korrani, G. Jerauld","doi":"10.2118/209412-ms","DOIUrl":"https://doi.org/10.2118/209412-ms","url":null,"abstract":"\u0000 Low salinity relative permeability curves are required to estimate the benefit of low salinity waterflooding at the field-level. Low salinity benefit is measured from corefloods (i.e., at the plug scale) and the same benefit is often assumed in full field models to generate low salinity curves from high salinity curves (often pseudo curves). The validity of this assumption is investigated. We present how uncertainty distribution of low salinity benefit can be propagated through an ensemble of full field models in which each simulation case could have a set of distinctive high salinity pseudos. A 0.5-ft vertical resolution sector and its 10-ft upscaled counterpart are used. Low salinity benefit from corefloods is used to generate low salinity relative permeabilities for the high-resolution sector. Rock curves (relative permeability curves from corefloods) are used in the high-resolution sector to create \"truth\" profiles. Pseudo high and low salinity curves are generated for the upscaled sector by history matching high salinity and incremental low salinity truth case profiles. Low salinity benefit from the upscaled model is compared against that of high-resolution sector (\"truth\" model). It is crucial to include capillary pressure in high resolution models. In the case studied, analogue and published data are used to produce low salinity capillary pressure curves.\u0000 Our results show that generating low salinity curves for high salinity pseudos using low salinity benefit from corefloods slightly underestimates the true low salinity benefit at field-scale (i.e., low salinity benefit estimated from high-resolution models). This conclusion is consistent for two extreme relative-permeability scenarios tested (i.e., a high total mobility-unfavorable fractional flow and low total mobility-favorable fractional flow). We demonstrate how a set of high salinity relative-permeability data obtained from corefloods, which encompasses a range for fractional flow and total mobility, can be included in ensemble modeling appropriately, and how low salinity benefit could be estimated for such an ensemble. It is adequate to generate low salinity curves for bounding high salinity sets of curves. The bounding low salinity curves can then be used to estimate low salinity curve for any interpolated high salinity curve. This significantly simplifies the process of generating a probability distribution function (pdf) of low salinity benefit for an ensemble of models, where each model has a different high salinity relative permeability. We explain the pseudoization process and how to generate a counterpart low salinity curve for a high salinity relative permeability that honors an estimated low salinity benefit from corefloods. We present how a pdf of low salinity benefit can be built for an ensemble of models with distinctive high salinity curves that each honors the low salinity benefit. The workflow simplifies the process of describing the uncertainty in the benefit of l","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89327112","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents an overview of both research advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in matured or maturing reservoirs. The advancements of offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, it also assesses the chemical formulations applied or studied and injection/production facilities required in the offshore environments. Main technical challenges are presented for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The technologies reviewed include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full field applications. It is feasible to implement offshore polymer injection either on platform or FPSO system. It is recommended to implement polymer flooding at early stage of reservoir development in order to maximize the investment of offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue in offshore polymer flooding. There are also some interesting research findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials including the single well tracer tests on surfactant, alkaline-surfactant, surfactant-polymer in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low partially due to their complex interactions with subsurface fluids and lack of much interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant based chemical flooding processes for offshore applica
{"title":"Review of Offshore Chemical Flooding Field Applications and Lessons Learned","authors":"M. Han, S. Ayirala, A. Al-yousef","doi":"10.2118/209473-ms","DOIUrl":"https://doi.org/10.2118/209473-ms","url":null,"abstract":"\u0000 This paper presents an overview of both research advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in matured or maturing reservoirs. The advancements of offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, it also assesses the chemical formulations applied or studied and injection/production facilities required in the offshore environments. Main technical challenges are presented for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems.\u0000 The technologies reviewed include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full field applications. It is feasible to implement offshore polymer injection either on platform or FPSO system. It is recommended to implement polymer flooding at early stage of reservoir development in order to maximize the investment of offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue in offshore polymer flooding.\u0000 There are also some interesting research findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials including the single well tracer tests on surfactant, alkaline-surfactant, surfactant-polymer in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low partially due to their complex interactions with subsurface fluids and lack of much interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant based chemical flooding processes for offshore applica","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"67 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86431782","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
J. Juri, G. Dupuis, G. Pedersen, A. Ruiz, V. Serrano, P. Guillen, F. Schein, I. Ylitch, N. Ojeda, S. Gandi, L. Martino, A. Lucero, D. Perez, G. Vocaturo, C. Rivas, J. Massaferro
Implementing a polymer flooding plan from laboratory studies to expansion and optimization takes around 8 to 12 years. What is the best approach to increase the project return on investment (ROI) and reduce the risk? EOR is facing, more than ever before, the importance and impact of timing. The oil demand is under rapid replacement because the energy transition is being accelerated by the pandemic. We built our strategy around a distributed polymer injection rather than a centralized infrastructure to massively inject polymer at full-field scale. The distributed polymer injection with modular mobile polymer injection units (PIUs) targets the richest zones/sweet- spots of by-passed oil. In this case, the logistics, the construction of small modular mobile polymer injection units along with a cluster of ten injectors and nineteen to twenty-five producers ensure that the development cost will be below $5/bbl. The distributed polymer injection not only is efficient in kg of polymer per incremental barrel but also rationalizes OPEX. Progressing this scenario is simple and depends mainly on the engineering and construction to move and mount rapidly the PIU from one sweet-spots to the next one. Our development strategy focused on speed over scale: less use of water, less footprint, less infrastructure, optimize OPEX (polymer is being consumed along four to seven years, there is scope to optimize along the project lifetime) on the contrary infrastructure an upfront cost (there is less scope to optimize in the project lifetime). We prioritize small/mobile facilities knowing the specific location of the best reservoir targets in the subsurface to inject polymer. This offered the opportunity to standardize engineering and materials for mounting the modules, and it provides a way to focusing on one type of infrastructure to optimize. Grimbeek Field, case study shows how we have increased the return of investment by identifying the sweet-spots of by-passed oil using reservoir simulation. In each of the main sweet-spots, we installed a modular mobile polymer injection unit. Reservoir simulation shows that only 38% of the reservoir affected by polymer injection produces more than 60% of the incremental oil. Grimbeek Field produced 4100 BOPD in 2019. Development of sweet-spots by modular polymer injection has driven the production of over 9700 BOPD incrementing production in more than 100% (more than 5000 BOPD) which now represents 23% of Manantiales Behr total production in less than two years including 2020. In the next 10 months, the project will have delivered 60% of the total cumulative production rationalizing the operative expenditure. This strategy is a game-changer in polymer flooding, not only because other companies worldwide are adopting the distributed polymer injection concept but also because companies that initially adopted centralized infrastructure to massively inject polymer are now abandoning this concept and shifting towards distribut
{"title":"Agile Scalable Distributed Polymer Injection Achieves 23% of Manantiales Behr Oil Production 2 Years; Worldwide Examples of this Game Changer Strategy","authors":"J. Juri, G. Dupuis, G. Pedersen, A. Ruiz, V. Serrano, P. Guillen, F. Schein, I. Ylitch, N. Ojeda, S. Gandi, L. Martino, A. Lucero, D. Perez, G. Vocaturo, C. Rivas, J. Massaferro","doi":"10.2118/209364-ms","DOIUrl":"https://doi.org/10.2118/209364-ms","url":null,"abstract":"\u0000 Implementing a polymer flooding plan from laboratory studies to expansion and optimization takes around 8 to 12 years. What is the best approach to increase the project return on investment (ROI) and reduce the risk? EOR is facing, more than ever before, the importance and impact of timing. The oil demand is under rapid replacement because the energy transition is being accelerated by the pandemic.\u0000 We built our strategy around a distributed polymer injection rather than a centralized infrastructure to massively inject polymer at full-field scale. The distributed polymer injection with modular mobile polymer injection units (PIUs) targets the richest zones/sweet- spots of by-passed oil. In this case, the logistics, the construction of small modular mobile polymer injection units along with a cluster of ten injectors and nineteen to twenty-five producers ensure that the development cost will be below $5/bbl. The distributed polymer injection not only is efficient in kg of polymer per incremental barrel but also rationalizes OPEX. Progressing this scenario is simple and depends mainly on the engineering and construction to move and mount rapidly the PIU from one sweet-spots to the next one.\u0000 Our development strategy focused on speed over scale: less use of water, less footprint, less infrastructure, optimize OPEX (polymer is being consumed along four to seven years, there is scope to optimize along the project lifetime) on the contrary infrastructure an upfront cost (there is less scope to optimize in the project lifetime). We prioritize small/mobile facilities knowing the specific location of the best reservoir targets in the subsurface to inject polymer. This offered the opportunity to standardize engineering and materials for mounting the modules, and it provides a way to focusing on one type of infrastructure to optimize.\u0000 Grimbeek Field, case study shows how we have increased the return of investment by identifying the sweet-spots of by-passed oil using reservoir simulation. In each of the main sweet-spots, we installed a modular mobile polymer injection unit. Reservoir simulation shows that only 38% of the reservoir affected by polymer injection produces more than 60% of the incremental oil.\u0000 Grimbeek Field produced 4100 BOPD in 2019. Development of sweet-spots by modular polymer injection has driven the production of over 9700 BOPD incrementing production in more than 100% (more than 5000 BOPD) which now represents 23% of Manantiales Behr total production in less than two years including 2020. In the next 10 months, the project will have delivered 60% of the total cumulative production rationalizing the operative expenditure.\u0000 This strategy is a game-changer in polymer flooding, not only because other companies worldwide are adopting the distributed polymer injection concept but also because companies that initially adopted centralized infrastructure to massively inject polymer are now abandoning this concept and shifting towards distribut","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82545076","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs begs for utilization of tertiary recovery techniques. Enhanced Oil Recovery (EOR) via cyclic gas injection ("huff ‘n puff") has indeed enhanced oil recovery in many fields and many of those projects have also been documented in industry technical papers/case studies. But the need remains to document new techniques in new reservoirs. This paper documents a small scale EOR pilot project in the eastern Eagle Ford and shows promising well results. In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes and the learnings from each cycle led to adjustments and facility changes to improve the next cycle. After completing five injection/withdrawal cycles in the pilot a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable allowing for economic modeling to be utilized to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.
{"title":"Small Scale EOR Pilot in the Eastern Eagle Ford Boosts Production","authors":"Tim Bozeman, W. Nelle, Q. Nguyen","doi":"10.2118/209429-ms","DOIUrl":"https://doi.org/10.2118/209429-ms","url":null,"abstract":"\u0000 Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs begs for utilization of tertiary recovery techniques. Enhanced Oil Recovery (EOR) via cyclic gas injection (\"huff ‘n puff\") has indeed enhanced oil recovery in many fields and many of those projects have also been documented in industry technical papers/case studies. But the need remains to document new techniques in new reservoirs. This paper documents a small scale EOR pilot project in the eastern Eagle Ford and shows promising well results.\u0000 In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes and the learnings from each cycle led to adjustments and facility changes to improve the next cycle.\u0000 After completing five injection/withdrawal cycles in the pilot a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable allowing for economic modeling to be utilized to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88069626","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
During miscible gas injection for enhanced oil recovery, the composition of the fluids can change throughout the reservoir as the oil and gas phases develop miscibility. Measuring and modeling relative permeability as compositional regions are traversed creates many challenges. In simulators, the association of each phase with a relative permeability curve sometimes creates discontinuities when phases disappear across miscibility boundaries. Some newer relative permeability models attempt to resolve these issues by changing the standard "oil" and "gas" method of phase labeling and instead labeling phases according to a physical property that is continuous and tied to composition, most notably the fluid density or Gibbs free energy (GFE). Ideally, a relative permeability model will be based on experimental measurements. A handful of all relative permeability experiments focus on studying changes in relative permeability brought about by changes in fluid composition with increasing capillary number. However, there is also evidence to suggest that composition can impact relative permeability even at capillary numbers well below the capillary desaturation threshold. In this research, two-phase gas/oil core flood experiments were performed with ethane as the gas phase and equilibrated octane as the oil phase. Pressure was varied so that the composition (density and GFE) of the gas and oil were changing. The capillary numbers were kept low and constant to prevent capillary desaturation of the oil phase. The experiments were then repeated with an added residual brine phase to test the effect of composition with a third phase present. The results show that changing the density and GFE of the oil and gas phases in either two-phase or three-phase flow had no impact on the relative permeability curves. However, significant changes were observed when comparing two-phase to three-phase oil and gas relative permeabilities. When only gas and oil were flowing in the core, the oil phase formed a continuous layer on the pore surfaces. The addition of residual brine caused the oil to form droplets, reducing the relative permeability of both the oil and gas phases in the absence of a continuous layer of oil. These findings verify previous history-matched relative permeabilities in literature and show that the oil phase connectivity is more important than compositional parameters.
{"title":"Oil and Gas Relative Permeability as a Function of Fluid Composition","authors":"Lauren Churchwell, D. DiCarlo","doi":"10.2118/209388-ms","DOIUrl":"https://doi.org/10.2118/209388-ms","url":null,"abstract":"\u0000 During miscible gas injection for enhanced oil recovery, the composition of the fluids can change throughout the reservoir as the oil and gas phases develop miscibility. Measuring and modeling relative permeability as compositional regions are traversed creates many challenges. In simulators, the association of each phase with a relative permeability curve sometimes creates discontinuities when phases disappear across miscibility boundaries. Some newer relative permeability models attempt to resolve these issues by changing the standard \"oil\" and \"gas\" method of phase labeling and instead labeling phases according to a physical property that is continuous and tied to composition, most notably the fluid density or Gibbs free energy (GFE).\u0000 Ideally, a relative permeability model will be based on experimental measurements. A handful of all relative permeability experiments focus on studying changes in relative permeability brought about by changes in fluid composition with increasing capillary number. However, there is also evidence to suggest that composition can impact relative permeability even at capillary numbers well below the capillary desaturation threshold. In this research, two-phase gas/oil core flood experiments were performed with ethane as the gas phase and equilibrated octane as the oil phase. Pressure was varied so that the composition (density and GFE) of the gas and oil were changing. The capillary numbers were kept low and constant to prevent capillary desaturation of the oil phase. The experiments were then repeated with an added residual brine phase to test the effect of composition with a third phase present. The results show that changing the density and GFE of the oil and gas phases in either two-phase or three-phase flow had no impact on the relative permeability curves. However, significant changes were observed when comparing two-phase to three-phase oil and gas relative permeabilities. When only gas and oil were flowing in the core, the oil phase formed a continuous layer on the pore surfaces. The addition of residual brine caused the oil to form droplets, reducing the relative permeability of both the oil and gas phases in the absence of a continuous layer of oil. These findings verify previous history-matched relative permeabilities in literature and show that the oil phase connectivity is more important than compositional parameters.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"84 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83976632","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Chandrasekhar, D. Alexis, J. Jin, Taimur Malik, V. Dwarakanath
Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection. In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
在过去十年中，雪佛龙在英国近海的Captain油田以不同规模注入了乳液聚合物(Poulsen等人，2018)。试验水平井的注入能力下降速度比设计的要快，Jackson等人(2019)记录了造成油相损害的原因，包括a)在分离不完全后注入含有原油的采出水，b)注入的乳液聚合物的载体油被夹带。这些井采用表面活性剂增产措施进行修复(Alexis等，2021;Dwarakanath et al.， 2016)。补救措施提高了近井水的相对渗透率，增强了注入能力，并为后续连续注入聚合物提供了更高的处理率。在这项工作中，我们在不同尺寸和模式的替代岩板中进行了一组岩心注水，以证明在一般情况下近井增产的有益效果。注入0.04 PV的修复包，我们在整个实验中显示出一致的注入增强。我们证明了与a)残余油饱和度和b)粘性指指的流动阻力相比，井表皮处理对压降剖面的主要影响。该研究结果对在项目生命周期内保持高聚合物驱处理速率的注入能力具有重要的指导意义。干净的注入液被证明可以保持注入能力。证明了注水井增产措施对具有不利粘度比的稠油油藏的适用性。亚历克西斯等人(2021)开发的修复包的坚固性也得到了证明，对粘性油和原位相分离聚合物都有效。我们估计了低化学剂量的线性驱动情况下的表皮和刺激深度，发现在0.33含油饱和度单位下注入0.04孔隙体积的表面活性剂，注入能力提高了31%。因此，表面活性剂增产措施广泛适用于油相表皮井。
{"title":"Polymer Injectivity Enhancement Using Chemical Stimulation: A Multi-Dimensional Study","authors":"S. Chandrasekhar, D. Alexis, J. Jin, Taimur Malik, V. Dwarakanath","doi":"10.2118/209425-ms","DOIUrl":"https://doi.org/10.2118/209425-ms","url":null,"abstract":"Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection.\u0000 In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"5 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78351323","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Gutierrez, Joan Sebastian García, Ruben Castro, Tatiana Yiceth Zafra, Jonattan Rojas, Rocio Macarena Ortiz, H. Quintero, H. García, Luis Niño, Jhon Amado, D. Quintero, M. Kiani
The Yariguí-Cantagallo is a mature oil field located in the western flank of the middle Magdalena valley basin in Colombia. Oil production started in 1941 and has been supported by water injection since 2008 with the aim of maintaining the pressure in the reservoir and increasing oil production. However, due to the channeling of the injected water, the water cut in some wells has been increasing, reaching values greater than 90%. Therefore, ECOPETROL S.A. implemented the first deep conformance treatment in Colombia through the design, execution, monitoring and evaluation of the technology in the YR-521 and YR-517 patterns for improving sweep efficiency of the waterflooding process. Brightwater® technology (also known as Thermally Active Polymer, TAP) has been used as an in-depth conformance improvement agent in reservoirs under waterflood suffering from the presence of thief zones or preferential flow channels. BrightWater® consists of expandable submicron particles injected downhole with a dispersive surfactant as a batch using injection water as a carrier. The selection of the injection patterns and treatment volume estimation was carried out through analysis of diagnostic plots and analytical pattern simulations. Treatment design and chemistry selection were based on reservoir characteristics, especially the temperature profile between the injector and offset producing wells in each pattern. Thus, laboratory tests with the representative fluids at various temperatures were carried out. Injection in the first pattern began on December 14, 2020, with a cumulative 6344 bbls of water containing TAP, at an injection rate of 700 bpd, gradually increasing the concentration from 3,500 ppm to 12,000 ppm. Once the injection was completed in this pattern and using the same surface facility, the second injection pattern was executed, on December 23, 2020. In the second pattern a cumulative of 9152 bbls of water containing TAP was injected at an injection rate of 700 bpd at concentration from 3500 ppm up to 8000 ppm. This paper summarizes the first TAP pilot implementation in Colombia and will describe the methodology and results of project QAQC monitoring and injection-production. Based on results to date, after one year monitoring (decrease in water cut up to 6%, in some wells, with consequent increase in oil recovery up to 18,642 STB), five additional treatments are planned in other injection patterns in this field between 2022 and 2023. It was validated that the deep conformance improvement technology allows blocking the preferential flow channels, reaching new areas with high oil saturation. Incremental oil production, potential increase in reserves, and reduction of OPEX due to lower water production were some of the observed benefits from this trial. Likewise, calculations show positive impacts in reducing the carbon footprint and water management.
{"title":"In-Depth Water Conformance Control: Design, Implementation and Surveillance of the First Thermally Active Polymers Treatment TAP in a Colombian Field","authors":"M. Gutierrez, Joan Sebastian García, Ruben Castro, Tatiana Yiceth Zafra, Jonattan Rojas, Rocio Macarena Ortiz, H. Quintero, H. García, Luis Niño, Jhon Amado, D. Quintero, M. Kiani","doi":"10.2118/209472-ms","DOIUrl":"https://doi.org/10.2118/209472-ms","url":null,"abstract":"\u0000 The Yariguí-Cantagallo is a mature oil field located in the western flank of the middle Magdalena valley basin in Colombia. Oil production started in 1941 and has been supported by water injection since 2008 with the aim of maintaining the pressure in the reservoir and increasing oil production. However, due to the channeling of the injected water, the water cut in some wells has been increasing, reaching values greater than 90%. Therefore, ECOPETROL S.A. implemented the first deep conformance treatment in Colombia through the design, execution, monitoring and evaluation of the technology in the YR-521 and YR-517 patterns for improving sweep efficiency of the waterflooding process.\u0000 Brightwater® technology (also known as Thermally Active Polymer, TAP) has been used as an in-depth conformance improvement agent in reservoirs under waterflood suffering from the presence of thief zones or preferential flow channels. BrightWater® consists of expandable submicron particles injected downhole with a dispersive surfactant as a batch using injection water as a carrier. The selection of the injection patterns and treatment volume estimation was carried out through analysis of diagnostic plots and analytical pattern simulations. Treatment design and chemistry selection were based on reservoir characteristics, especially the temperature profile between the injector and offset producing wells in each pattern. Thus, laboratory tests with the representative fluids at various temperatures were carried out.\u0000 Injection in the first pattern began on December 14, 2020, with a cumulative 6344 bbls of water containing TAP, at an injection rate of 700 bpd, gradually increasing the concentration from 3,500 ppm to 12,000 ppm. Once the injection was completed in this pattern and using the same surface facility, the second injection pattern was executed, on December 23, 2020. In the second pattern a cumulative of 9152 bbls of water containing TAP was injected at an injection rate of 700 bpd at concentration from 3500 ppm up to 8000 ppm.\u0000 This paper summarizes the first TAP pilot implementation in Colombia and will describe the methodology and results of project QAQC monitoring and injection-production. Based on results to date, after one year monitoring (decrease in water cut up to 6%, in some wells, with consequent increase in oil recovery up to 18,642 STB), five additional treatments are planned in other injection patterns in this field between 2022 and 2023.\u0000 It was validated that the deep conformance improvement technology allows blocking the preferential flow channels, reaching new areas with high oil saturation. Incremental oil production, potential increase in reserves, and reduction of OPEX due to lower water production were some of the observed benefits from this trial. Likewise, calculations show positive impacts in reducing the carbon footprint and water management.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77877369","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents a case study of implementation and results of cyclic injection EOR technique in Hoople field. It is located in Crosby and Lubbock Counties, west Texas and sits on the Eastern Shelf of the Midland Basin. The Hoople oil field, discovered in 1970's, is in its depletion stage with water cut greater than 95%. The reservoir rock consists of tidal flat dolomite and limestone interbedded with shale in Lower Permian Clear Fork Formation. Severe reservoir heterogeneity with low porosity and permeability are observed through core examination. This type of reservoir is suitable for cyclic injection. Cyclic injection consists of two stages for water injection: pressurization (or injection) and depressurization (injection shut-in). Cyclic injection was initiated in part of the Hoople field in 2020. We selected two sections in the field for pilot testing and completed a full cycle in each section. After encouraging results, the cyclic injection technique was deployed over the whole field. The large-scale operation consists dividing the field in four sectors to maximize water handling and optimize cyclic injection operations. Cyclic water injection has generated positive results. During depressurizing (or shut-in) half cycle, water production decreased dramatically with increasing oil-cut. Water production decreased 10% in each area while oil-cut improvement ranges from 13% to 33%. During the pressurizing (or injection) half cycle, oil production increases with total fluid production. The observed increase in total production ranges between 10% to 19%. The most significant finding is the consistent reservoir oil production and oil-cut response. Overall oil production has been kept at a stable level, countering the expected natural decline, suggesting that the cyclic injection led to enhanced oil recovery. Overall water production dropped significantly, reducing the cost associated with lifting from and injecting back to the reservoir. Cyclic injection has a very positive impact on the financial performance of the field development. The cyclic injection methodology, an alternative EOR technique, can be applied to other mature fields with similar reservoir properties.
{"title":"Optimizing Waterflooding EOR Through Cyclic Injection: A Case Study on the Hoople Field, Midland Basin, West Texas","authors":"M. Farias, Xijin Liu","doi":"10.2118/209434-ms","DOIUrl":"https://doi.org/10.2118/209434-ms","url":null,"abstract":"This paper presents a case study of implementation and results of cyclic injection EOR technique in Hoople field. It is located in Crosby and Lubbock Counties, west Texas and sits on the Eastern Shelf of the Midland Basin. The Hoople oil field, discovered in 1970's, is in its depletion stage with water cut greater than 95%. The reservoir rock consists of tidal flat dolomite and limestone interbedded with shale in Lower Permian Clear Fork Formation. Severe reservoir heterogeneity with low porosity and permeability are observed through core examination. This type of reservoir is suitable for cyclic injection.\u0000 Cyclic injection consists of two stages for water injection: pressurization (or injection) and depressurization (injection shut-in). Cyclic injection was initiated in part of the Hoople field in 2020. We selected two sections in the field for pilot testing and completed a full cycle in each section. After encouraging results, the cyclic injection technique was deployed over the whole field. The large-scale operation consists dividing the field in four sectors to maximize water handling and optimize cyclic injection operations.\u0000 Cyclic water injection has generated positive results. During depressurizing (or shut-in) half cycle, water production decreased dramatically with increasing oil-cut. Water production decreased 10% in each area while oil-cut improvement ranges from 13% to 33%. During the pressurizing (or injection) half cycle, oil production increases with total fluid production. The observed increase in total production ranges between 10% to 19%. The most significant finding is the consistent reservoir oil production and oil-cut response. Overall oil production has been kept at a stable level, countering the expected natural decline, suggesting that the cyclic injection led to enhanced oil recovery. Overall water production dropped significantly, reducing the cost associated with lifting from and injecting back to the reservoir. Cyclic injection has a very positive impact on the financial performance of the field development.\u0000 The cyclic injection methodology, an alternative EOR technique, can be applied to other mature fields with similar reservoir properties.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84469783","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Saeedeh Mohebbinia, S. Pennell, R. Valdez, K. Eskandaridalvand
Implementation of a second Double Displacement Process (DDP2) has been evaluated for Yates Field Unit (YFU). A DDP2 Demonstration Area Project has been designed to test DDP2 in a mature, high recovery area of the field. A detailed, geologically based reservoir description was used to build a simulation model for the DDP2 pilot area to study the DDP process and evaluate DDP2 performance. Initial saturations and relative permeability curves were generated based on a capillary pressure based Saturation Height Function (SHF) study. The fracture system was simulated using a hybrid dual porosity/permeability system. A 9-component equation of state (EOS) was used to model the YFU fluid properties. Capillary pressure of imbibition is used to capture the effect of hysteresis and oil trapping in the zones invaded by the aquifer during primary depletion. The simulation model has been tuned against historical performance since 1927, focusing on the first DDP process (DDP1) implemented over 1992-2000. Matching historical production/injection, field pressure and fluid contacts data were the history matching objectives. The DDP2 pilot project will include lowering 31 Horizontal Drain Hole (HDH) lateral completions by 25 feet to lower the contacts. The tuned model has been used to generate flow streams for different forecasting scenarios utilizing the DDP2 process. Forecast results show incremental oil recovery by lowering the contacts by 25 feet during the DDP2 phase. This paper presents a comprehensive study of YFU DDP1 process and evaluation of the second DDP process by a 3D numerical simulation model. The simulation model is used to improve understanding of the complex Gas-Oil Gravity Drainage (GOGD) and Gas Assisted Gravity Drainage (GAGD), and provide forecasts for the DDP2 process. Success of the pilot will result in extending the field life another 10-20 years.
{"title":"Evaluation of Historical and Ongoing Double Displacement Process in Yates Field Unit","authors":"Saeedeh Mohebbinia, S. Pennell, R. Valdez, K. Eskandaridalvand","doi":"10.2118/209374-ms","DOIUrl":"https://doi.org/10.2118/209374-ms","url":null,"abstract":"\u0000 Implementation of a second Double Displacement Process (DDP2) has been evaluated for Yates Field Unit (YFU). A DDP2 Demonstration Area Project has been designed to test DDP2 in a mature, high recovery area of the field. A detailed, geologically based reservoir description was used to build a simulation model for the DDP2 pilot area to study the DDP process and evaluate DDP2 performance. Initial saturations and relative permeability curves were generated based on a capillary pressure based Saturation Height Function (SHF) study. The fracture system was simulated using a hybrid dual porosity/permeability system. A 9-component equation of state (EOS) was used to model the YFU fluid properties. Capillary pressure of imbibition is used to capture the effect of hysteresis and oil trapping in the zones invaded by the aquifer during primary depletion. The simulation model has been tuned against historical performance since 1927, focusing on the first DDP process (DDP1) implemented over 1992-2000. Matching historical production/injection, field pressure and fluid contacts data were the history matching objectives. The DDP2 pilot project will include lowering 31 Horizontal Drain Hole (HDH) lateral completions by 25 feet to lower the contacts. The tuned model has been used to generate flow streams for different forecasting scenarios utilizing the DDP2 process. Forecast results show incremental oil recovery by lowering the contacts by 25 feet during the DDP2 phase. This paper presents a comprehensive study of YFU DDP1 process and evaluation of the second DDP process by a 3D numerical simulation model. The simulation model is used to improve understanding of the complex Gas-Oil Gravity Drainage (GOGD) and Gas Assisted Gravity Drainage (GAGD), and provide forecasts for the DDP2 process. Success of the pilot will result in extending the field life another 10-20 years.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87773133","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Yutaro Kaito, Ayae Goto, D. Ito, S. Murakami, Hirotake Kitagawa, Takahiro Ohori
"Nanoparticle-based enhanced oil recovery (Nano-EOR)" is an improved waterflooding assisted by nanoparticles dispersed in the injection water. Many laboratory studies have revealed the effectiveness of Nano-EOR. An evaluation of the EOR effect is one of the most critical items to be investigated. However, risk assessments and mitigation plans are as essential as investigation of its effectiveness for field applications. This study examined the items to be concerned for applying Nano-EOR to the Sarukawa oil field, a mature field in Japan, and established an organized laboratory and field tests workflow. This paper discusses a laboratory part of the study in detail. This study investigated the effect and potential risks of the Nano-EOR through laboratory experiments based on the workflow. The laboratory tests used surface-modified nanosilica dispersion, synthetic brine, injection water, and crude oil. The oil and injection water were sampled from a wellhead and injection facility, respectively, to examine the applicability of the EOR at the Sarukawa oil field. The items of the risk assessment involved the influence on an injection well's injectivity, poor oil/water separation at a surface facility, and contamination of sales oil. A series of experiments intended for the Sarukawa oil field showed that 0.5 wt. % nanofluid was expected to contribute to significant oil recovery and cause no damage on an injection well for the reservoir with tens of mD. This is considered a favorable result for applying Nano-EOR to Sarukawa oil field because it contains layers of tens mD. Furthermore, the experiments also showed that 0.5 wt.% nanofluid did not lead to poor oil/water separation and contamination of sales oil. Thus, field tests are designed with this concentration. This paper introduces the entire study workflow and discusses the detailed procedure and results of experiments investigating the Nano-EOR effect and potential risks.
{"title":"First Nanoparticle-Based EOR Nano-EOR Project in Japan: Laboratory Experiments for a Field Pilot Test","authors":"Yutaro Kaito, Ayae Goto, D. Ito, S. Murakami, Hirotake Kitagawa, Takahiro Ohori","doi":"10.2118/209467-ms","DOIUrl":"https://doi.org/10.2118/209467-ms","url":null,"abstract":"\u0000 \"Nanoparticle-based enhanced oil recovery (Nano-EOR)\" is an improved waterflooding assisted by nanoparticles dispersed in the injection water. Many laboratory studies have revealed the effectiveness of Nano-EOR. An evaluation of the EOR effect is one of the most critical items to be investigated. However, risk assessments and mitigation plans are as essential as investigation of its effectiveness for field applications. This study examined the items to be concerned for applying Nano-EOR to the Sarukawa oil field, a mature field in Japan, and established an organized laboratory and field tests workflow. This paper discusses a laboratory part of the study in detail.\u0000 This study investigated the effect and potential risks of the Nano-EOR through laboratory experiments based on the workflow. The laboratory tests used surface-modified nanosilica dispersion, synthetic brine, injection water, and crude oil. The oil and injection water were sampled from a wellhead and injection facility, respectively, to examine the applicability of the EOR at the Sarukawa oil field. The items of the risk assessment involved the influence on an injection well's injectivity, poor oil/water separation at a surface facility, and contamination of sales oil.\u0000 A series of experiments intended for the Sarukawa oil field showed that 0.5 wt. % nanofluid was expected to contribute to significant oil recovery and cause no damage on an injection well for the reservoir with tens of mD. This is considered a favorable result for applying Nano-EOR to Sarukawa oil field because it contains layers of tens mD. Furthermore, the experiments also showed that 0.5 wt.% nanofluid did not lead to poor oil/water separation and contamination of sales oil. Thus, field tests are designed with this concentration.\u0000 This paper introduces the entire study workflow and discusses the detailed procedure and results of experiments investigating the Nano-EOR effect and potential risks.","PeriodicalId":10935,"journal":{"name":"Day 1 Mon, April 25, 2022","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77403687","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：