M. T. Al-Murayri, D. Alrukaibi, Dawood S. Kamal, A. Al-Rabah, A. Hassan, Faisal Qureshi, M. Delshad, J. Driver, Zhitao Li, S. Badham, C. Bouma, E. Zijlstra
This paper describes the design and implementation of a one-spot enhanced oil recovery (EOR) pilot using high-salinity water (∼166,000 ppm TDS) in a sour, sandstone, heavy-oil reservoir (∼5 mol% hydrogen sulfide) based on an extensive laboratory study involving different polymers and operating conditions. In view of the results of this one-spot EOR pilot, a multi-well, high-salinity polymer-injection pilot is expected to start in 2020 targeting the Umm Niqqa Lower Fars (UNLF) reservoir in Kuwait. Polymer flooding is normally carried out using low- to moderate-salinity water to maintain favorable polymer solution viscosities in pursuit of maximum oil recovery. Nevertheless, low- to moderate-salinity water sources such as seawater tend to be associated with a variety of logistical, operational, and commercial challenges. For this study, laboratory experiments were conducted in conjunction with reservoir simulation to confirm the technical viability of polymer flooding using high-salinity water. Thereafter, a one-spot EOR pilot was executed in the field using a well near the location of the planned multi-well pilot to confirm the performance of the selected polymer vis-à-vis injectivity and oil desaturation. The one-spot EOR pilot described in this paper was successfully executed by performing two Single-Well Chemical Tracer (SWCT) tests. For the first stage of the pilot, 200 bbl of produced water (up to 166,000 ppm TDS) were injected into the test well in an attempt to displace mobile oil out of the investigated pore space. Following this produced water injection, an SWCT test (Test #1) was carried out and measured the remaining oil saturation to be 0.41 ± 0.03. This saturation measurement represents the fraction of oil remaining in the pore space of a cylindrical portion of the Lower Fars reservoir, measured from the wellbore out to a radius of 3.02 feet, after produced water injection. After the completion of Test #1 and subsequent recovery of the injected produced water, the same zone was treated with a 200-bbl injection of polymer solution. Following this 200-bbl polymer injection, a second SWCT test (Test #2) was performed and measured the remaining oil saturation to be 0.19 ± 0.03 out to a radius of 3.38 feet. These results indicate that polymer injection may offer considerable improvement to oil recovery over conventional waterflooding alone. Performing polymer flooding in a sour, heavy-oil reservoir using high-salinity water is a challenging and unprecedented undertaking worldwide. In addition to the improved incremental oil recovery demonstrated by this pilot, enabling the use high-salinity produced water for polymer flooding is expected to result in significant benefits for cost-efficiency and operational ease by reducing or eliminating problems commonly associated with the sourcing, treatment, and handling of less saline water in the field.
{"title":"Transforming Challenges into Opportunities: First High Salinity Polymer Injection Deployment in a Sour Sandstone Heavy Oil Reservoir","authors":"M. T. Al-Murayri, D. Alrukaibi, Dawood S. Kamal, A. Al-Rabah, A. Hassan, Faisal Qureshi, M. Delshad, J. Driver, Zhitao Li, S. Badham, C. Bouma, E. Zijlstra","doi":"10.2118/200317-ms","DOIUrl":"https://doi.org/10.2118/200317-ms","url":null,"abstract":"\u0000 This paper describes the design and implementation of a one-spot enhanced oil recovery (EOR) pilot using high-salinity water (∼166,000 ppm TDS) in a sour, sandstone, heavy-oil reservoir (∼5 mol% hydrogen sulfide) based on an extensive laboratory study involving different polymers and operating conditions. In view of the results of this one-spot EOR pilot, a multi-well, high-salinity polymer-injection pilot is expected to start in 2020 targeting the Umm Niqqa Lower Fars (UNLF) reservoir in Kuwait.\u0000 Polymer flooding is normally carried out using low- to moderate-salinity water to maintain favorable polymer solution viscosities in pursuit of maximum oil recovery. Nevertheless, low- to moderate-salinity water sources such as seawater tend to be associated with a variety of logistical, operational, and commercial challenges. For this study, laboratory experiments were conducted in conjunction with reservoir simulation to confirm the technical viability of polymer flooding using high-salinity water. Thereafter, a one-spot EOR pilot was executed in the field using a well near the location of the planned multi-well pilot to confirm the performance of the selected polymer vis-à-vis injectivity and oil desaturation.\u0000 The one-spot EOR pilot described in this paper was successfully executed by performing two Single-Well Chemical Tracer (SWCT) tests. For the first stage of the pilot, 200 bbl of produced water (up to 166,000 ppm TDS) were injected into the test well in an attempt to displace mobile oil out of the investigated pore space. Following this produced water injection, an SWCT test (Test #1) was carried out and measured the remaining oil saturation to be 0.41 ± 0.03. This saturation measurement represents the fraction of oil remaining in the pore space of a cylindrical portion of the Lower Fars reservoir, measured from the wellbore out to a radius of 3.02 feet, after produced water injection. After the completion of Test #1 and subsequent recovery of the injected produced water, the same zone was treated with a 200-bbl injection of polymer solution. Following this 200-bbl polymer injection, a second SWCT test (Test #2) was performed and measured the remaining oil saturation to be 0.19 ± 0.03 out to a radius of 3.38 feet. These results indicate that polymer injection may offer considerable improvement to oil recovery over conventional waterflooding alone.\u0000 Performing polymer flooding in a sour, heavy-oil reservoir using high-salinity water is a challenging and unprecedented undertaking worldwide. In addition to the improved incremental oil recovery demonstrated by this pilot, enabling the use high-salinity produced water for polymer flooding is expected to result in significant benefits for cost-efficiency and operational ease by reducing or eliminating problems commonly associated with the sourcing, treatment, and handling of less saline water in the field.","PeriodicalId":251499,"journal":{"name":"Day 2 Tue, September 01, 2020","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-08-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121776213","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}
I. C. Salmo, N. Zamani, T. Skauge, K. Sorbie, A. Skauge
Any aqueous solution viscosified by a polymer (or glycerol) should improve the recovery of a very viscous oil to some degree, but it has long been thought that the detailed rheology of the solution would not play a major role. However, recent heavy oil displacement experiments have shown that there are clear differences in incremental oil recovery between aqueous polymeric or Newtonian solutions viscosified to the same effective viscosity. For example, synthetic polymers (such as HPAM) recover more oil than biopolymers (such as xanthan) at the same effective viscosity. In this paper, we use dynamic pore scale network modeling to model and explain these experimental results. A previously published dynamic pore scale network model (DPNM) which can model imbibition, has been extended to include polymer displacements, where the polymer may have any desired rheological properties. Using this model, we compare viscous oil displacement by water (Newtonian) with polymer injection where the "polymer" may be Newtonian (e.g. glycerol solution), or purely shear-thinning (e.g. xanthan) or it may show combined shear thinning and thickening behaviour (e.g. HPAM). In the original experiments, the polymer concentrations were adjusted such that the in situ viscosities of each solution were comparable at the expected in situ average shear rates (see Vik et al, 2018). The rheological properties of the injected "polymer" solutions in the dynamic pore network model (DPNM), were also chosen such that they had the same effective viscosity at a given injection rate, in single phase aqueous flow in the network model. Secondary mode injections of HPAM, xanthan and glycerol (Newtonian) showed significant differences in recovery efficiency and displacement, both experimentally and numerically. All polymers increased the oil production compared to water injection. However, the more complex shear thinning/thickening polymer (HPAM) recovered most oil, while the shear-thinning xanthan produced the lowest oil recovery, and the recovery by glycerol (Newtonian) was in the middle. In accordance with experimental results, at adverse mobility ratio, the DPNM results also showed that the combined shear- thinning/thickening (HPAM) polymer improves oil recovery the most, and the shear-thinning polymer (xanthan) shows the least incremental oil recovery with the Newtonian polymer (glycerol) recovery being in the middle; i.e. excellent qualitative agreement with the experimental observations was found. The DPNM simulations for the shear-thinning/thickening polymer show that in this case there is better front stability and increased oil mobilization at the pore level, thus leaving less oil behind. Simulations for the shear-thinning polymer show that in faster flowing bonds the average viscosity is greatly reduced and this causes enhanced water fingering compared with the Newtonian polymer (glycerol) case. The DPNM also allows us to explore phenomena such as piston-like displacements, sn
任何被聚合物(或甘油)增粘的水溶液都应该在一定程度上提高高粘度油的采收率，但长期以来人们一直认为，溶液的详细流变性不会起主要作用。然而，最近的稠油驱替实验表明，在相同的有效粘度下，水性聚合物溶液和牛顿溶液在增油采收率方面存在明显差异。例如，在相同的有效粘度下，合成聚合物(如HPAM)比生物聚合物(如黄原胶)回收更多的油。在本文中，我们使用动态孔隙尺度网络模型来模拟和解释这些实验结果。先前发布的动态孔隙尺度网络模型(DPNM)可以模拟渗吸，现已扩展到包括聚合物驱，其中聚合物可能具有任何所需的流变性能。使用该模型，我们比较了水驱(牛顿驱)和聚合物注入的稠油，其中“聚合物”可能是牛顿驱(例如甘油溶液)，或者纯粹的剪切稀释(例如黄原胶)，或者它可能显示剪切稀释和增稠的组合行为(例如HPAM)。在最初的实验中，调整了聚合物浓度，使每种溶液的原位粘度与预期的原位平均剪切速率相当(见Vik et al, 2018)。在动态孔隙网络模型(DPNM)中，注入的“聚合物”溶液的流变特性也被选择为在给定的注入速率下，在网络模型的单相水流动中具有相同的有效粘度。二次模式注射HPAM、黄原胶和甘油(牛顿)的采收率和驱替效果在实验和数值上都有显著差异。与注水相比，所有聚合物都提高了产油量。然而，更复杂的剪切减薄/增稠聚合物(HPAM)采收率最高，而剪切减薄黄原胶的采收率最低，甘油(牛顿)的采收率居中。与实验结果一致，在不利迁移率下，DPNM实验结果还表明，剪切减薄/增稠复合聚合物(HPAM)对采收率的提高最大，剪切减薄聚合物(黄原胶)的采收率增量最小，牛顿聚合物(甘油)的采收率居中;也就是说，发现了与实验观察极好的定性一致。对剪切减薄/增稠聚合物的DPNM模拟表明，在这种情况下，聚合物具有更好的前端稳定性，并且在孔隙水平上增加了油的动员，从而留下更少的油。剪切减薄聚合物的模拟表明，与牛顿聚合物(甘油)相比，在快速流动的键中，平均粘度大大降低，这导致了水指指的增强。DPNM还允许我们探索活塞式位移、断裂和膜流等现象，这些现象在孔隙水平上可能会影响各种流体注入方案的整体效率。DPNM模拟聚合物流变性能改变粘性/毛细力之间的平衡，从而实现流体微观转向，从而提高采收率。
{"title":"Use of Dynamic Pore Network Modeling to Improve Our Understanding of Experimental Observations in Viscous Oil Displacement by Polymers","authors":"I. C. Salmo, N. Zamani, T. Skauge, K. Sorbie, A. Skauge","doi":"10.2118/200387-ms","DOIUrl":"https://doi.org/10.2118/200387-ms","url":null,"abstract":"\u0000 Any aqueous solution viscosified by a polymer (or glycerol) should improve the recovery of a very viscous oil to some degree, but it has long been thought that the detailed rheology of the solution would not play a major role. However, recent heavy oil displacement experiments have shown that there are clear differences in incremental oil recovery between aqueous polymeric or Newtonian solutions viscosified to the same effective viscosity. For example, synthetic polymers (such as HPAM) recover more oil than biopolymers (such as xanthan) at the same effective viscosity. In this paper, we use dynamic pore scale network modeling to model and explain these experimental results.\u0000 A previously published dynamic pore scale network model (DPNM) which can model imbibition, has been extended to include polymer displacements, where the polymer may have any desired rheological properties. Using this model, we compare viscous oil displacement by water (Newtonian) with polymer injection where the \"polymer\" may be Newtonian (e.g. glycerol solution), or purely shear-thinning (e.g. xanthan) or it may show combined shear thinning and thickening behaviour (e.g. HPAM). In the original experiments, the polymer concentrations were adjusted such that the in situ viscosities of each solution were comparable at the expected in situ average shear rates (see Vik et al, 2018). The rheological properties of the injected \"polymer\" solutions in the dynamic pore network model (DPNM), were also chosen such that they had the same effective viscosity at a given injection rate, in single phase aqueous flow in the network model.\u0000 Secondary mode injections of HPAM, xanthan and glycerol (Newtonian) showed significant differences in recovery efficiency and displacement, both experimentally and numerically. All polymers increased the oil production compared to water injection. However, the more complex shear thinning/thickening polymer (HPAM) recovered most oil, while the shear-thinning xanthan produced the lowest oil recovery, and the recovery by glycerol (Newtonian) was in the middle. In accordance with experimental results, at adverse mobility ratio, the DPNM results also showed that the combined shear- thinning/thickening (HPAM) polymer improves oil recovery the most, and the shear-thinning polymer (xanthan) shows the least incremental oil recovery with the Newtonian polymer (glycerol) recovery being in the middle; i.e. excellent qualitative agreement with the experimental observations was found.\u0000 The DPNM simulations for the shear-thinning/thickening polymer show that in this case there is better front stability and increased oil mobilization at the pore level, thus leaving less oil behind. Simulations for the shear-thinning polymer show that in faster flowing bonds the average viscosity is greatly reduced and this causes enhanced water fingering compared with the Newtonian polymer (glycerol) case. The DPNM also allows us to explore phenomena such as piston-like displacements, sn","PeriodicalId":251499,"journal":{"name":"Day 2 Tue, September 01, 2020","volume":"71 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-08-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124620416","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}
CO2 storage through CO2 enhanced oil recovery (EOR) is considered as one of the technologies to help promote larger scale deployment of CO2 storage because of associated economic benefits through oil recovery, 45Q tax credits and the utilization of existing infrastructure. The objective of this study is to demonstrate how optimal reservoir management and operation strategies (including well completions and controls) can be used to optimize both CO2 storage and oil recovery. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection/oil production controls that maximize the net present value (NPV) in a CO2 EOR and storage operation. We utilized the newly developed StoSAG algorithm, one of the most efficient optimization algorithms in the reservoir management community, to solve the optimization problem. The performance of joint optimization approach was compared with the performance of well control only optimization approach. In addition, the performance of co-optimization of CO2 storage and oil recovery approach was compared with the performances of maximization of only CO2 storage and maximization of only oil recovery approaches. The optimization results showed that a joint optimization of well completions and well controls can achieve an 8.84% higher final NPV than the one obtained from the optimization of only well controls. It was observed that the NPV incremental for joint optimization is mainly due to the fact that the optimal well completions and controls approach results in efficient CO2 storage and oil production from different reservoir layers depending on the differences in individual layer properties. Comparison of co-optimization (i.e., maximization of NPV) and maximization of only CO2 storage or only oil recovery showed that the co-optimization and maximization of only oil recovery result in significantly higher final NPV than that obtained through maximization of only CO2 storage approach while maximization of only CO2 storage can achieve significantly higher CO2 storage in the reservoir compared to the other two scenarios. The similar results for co-optimization and maximization of oil production are obtained because of the difference in oil revenue compared to CO2 storage tax credit. To the best of our knowledge, this is the first study in oil/gas industry and CO2 storage community to perform joint optimization of well completions and well controls in the fields. We expect that the proposed optimization framework will be a useful and efficient tool for field engineers to optimally manage CO2 EOR projects to maximize revenue through oil recovery as well as CO2 storage by taking advantage of the new 45Q tax law.
{"title":"Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage","authors":"Bailian Chen, R. Pawar","doi":"10.2118/200316-ms","DOIUrl":"https://doi.org/10.2118/200316-ms","url":null,"abstract":"\u0000 CO2 storage through CO2 enhanced oil recovery (EOR) is considered as one of the technologies to help promote larger scale deployment of CO2 storage because of associated economic benefits through oil recovery, 45Q tax credits and the utilization of existing infrastructure. The objective of this study is to demonstrate how optimal reservoir management and operation strategies (including well completions and controls) can be used to optimize both CO2 storage and oil recovery.\u0000 The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection/oil production controls that maximize the net present value (NPV) in a CO2 EOR and storage operation. We utilized the newly developed StoSAG algorithm, one of the most efficient optimization algorithms in the reservoir management community, to solve the optimization problem. The performance of joint optimization approach was compared with the performance of well control only optimization approach. In addition, the performance of co-optimization of CO2 storage and oil recovery approach was compared with the performances of maximization of only CO2 storage and maximization of only oil recovery approaches.\u0000 The optimization results showed that a joint optimization of well completions and well controls can achieve an 8.84% higher final NPV than the one obtained from the optimization of only well controls. It was observed that the NPV incremental for joint optimization is mainly due to the fact that the optimal well completions and controls approach results in efficient CO2 storage and oil production from different reservoir layers depending on the differences in individual layer properties. Comparison of co-optimization (i.e., maximization of NPV) and maximization of only CO2 storage or only oil recovery showed that the co-optimization and maximization of only oil recovery result in significantly higher final NPV than that obtained through maximization of only CO2 storage approach while maximization of only CO2 storage can achieve significantly higher CO2 storage in the reservoir compared to the other two scenarios. The similar results for co-optimization and maximization of oil production are obtained because of the difference in oil revenue compared to CO2 storage tax credit.\u0000 To the best of our knowledge, this is the first study in oil/gas industry and CO2 storage community to perform joint optimization of well completions and well controls in the fields. We expect that the proposed optimization framework will be a useful and efficient tool for field engineers to optimally manage CO2 EOR projects to maximize revenue through oil recovery as well as CO2 storage by taking advantage of the new 45Q tax law.","PeriodicalId":251499,"journal":{"name":"Day 2 Tue, September 01, 2020","volume":"39 28","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-08-30","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120813163","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}
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