Day 2 Tue, September 01, 2020最新文献

{"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}

{"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}

{"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}